2 Oilfield Review

Subsea Solutions

Alan ChristieAshley KishinoRosharon, Texas, USA

John CrombTexaco Worldwide Exploration and ProductionHouston, Texas

Rodney HensleyBP Amoco CorporationHouston, Texas

Ewan KentBrian McBeathHamish StewartAlain VidalAberdeen, Scotland

Leo KootShellSarawak, Malaysia

For help in preparation of this article, thanks to RobertBrown, John Kerr and Keith Sargeant, SchlumbergerReservoir Evaluation, Aberdeen, Scotland; and MichaelFrugé, Andy Hill and Frank Mitton, Schlumberger ReservoirEvaluation, Houston, Texas, USA; EverGreen, E-Z Tree, IRIS (Intelligent Remote ImplementationSystem) and SenTREE are marks of Schlumberger.

All wells are not created equal. Subsea wells, which spring from

the ocean floor yet never see the light of day, have a life-style all

their own. Constructing these wells and keeping them flowing and

productive require heroic efforts that are now paying off.

1. Brandt W, Dang AS, Magne E, Crowley D, Houston K,Rennie A, Hodder M, Stringer R, Juiniti R, Ohara S,Rushton S: “Deepening the Search for OffshoreHydrocarbons,” Oilfield Review 10, no. 1 (Spring 1998): 2-21.

Winter 1999/2000 3

The mysteries and challenges of the world underthe sea have long enticed adventurers andexplorers. For thousands of years, people havespeculated on the existence of underwater civi-lizations and dreamed of discovering lost cities ordeveloping ways to live and work under the sea.

Underwater cities remain a fantastic vision,but some aspects of everyday industry do tran-spire at the bottom of the sea: early communica-tions cables crossed the ocean bottoms; researchdevices monitor properties of the earth and sea;and military surveillance equipment tracks suspi-cious activity—all as extensions of processesthat also take place on land.

Similarly, the oil and gas industry hasextended its early exploration and productionoperations with land-based rigs, wellheads andpipelines to tap the richness of the volume ofearth covered by ocean. This evolution from landto sea has occurred over the past century, start-ing in 1897 with the first derrick placed atop awharf on the California (USA) coast (right).1

Seagoing drilling equipment followed, with off-shore platforms, semisubmersible and jackupdrilling rigs, and dynamically positioned drill-ships. From one point on a fixed platform or float-ing rig, wells could be drilled in multipledirections to reach more of the reservoir.

As offshore technologies advanced to conquerincreasingly hostile and challenging environ-ments, offshore drilling moved forward in twomajor directions: First, and predictably, wellswere drilled at greater water depths every year,until the current water-depth record wasachieved—6077 ft [1852 m] for a producing wellin the Roncador field, offshore Brazil.2 Drilling forexploratory purposes, without actually producing,has been accomplished at the record depth of9050 ft [2777 m] for Petrobras offshore Brazil.OtherGulf of Mexico leases awaiting exploration reachwater depths of more than 10,000 ft [3050 m].

2. Bradbury J: “Brazilian Boost,” Deepwater Technology,Supplement to Petroleum Engineer International 72, no. 5(May 1999): 17, 19, 21.Deepwater has different working definitions. One defini-tion of deep is 2000 ft in hostile environments, 3000 ft[1100 m] otherwise. Another is deep for more than 400 m[1312 ft] and ultradeep at more than 1500 m [4922 ft].

> A time line of offshore operations.

Offshore drilling

1897 Derrick placed atop wharf 250 ft [76 m] from shore

1911 First drilling platform

1925 First artificial island for drilling

1932 First well drilled from independent platform

1953 First mobile submersible rigs

1956 Drill to 600-ft [183-m] water depth

1966 First jackup

Deepwater

1970 Guideline drilling in 1497-ft [456-m] water depth

1971 First dynamically positioned oil drillship

1987 Water depth drilling record of 7520 ft [2292 m]

1994 Water depth oil production record of 3370 ft [1027 m]

1996 Water depth oil production record of 5607 ft [1709 m]

Subsea

1961 First subsea Christmas tree

1973 First multiwell subsea template

1991 Record subsea tieback to 30 miles [48 km]

1992 First horizontal tree

1996 Record tieback to 68 miles [109 km]

1997 1000 subsea wells completed2000 Water depth

drilling record of 9050 ft [2777 m]

In a second direction, well-completion equip-ment has entered the water. Wellheads on theseafloor, in what is called a subsea completion,connect to flowlines that transport oil and gas tothe surface (above left). With multiple points ofaccess, more of the reservoir can be reachedthan through extended-reach wells, so the reser-voir volume can be exploited more thoroughly. Inaddition, field development costs can be greatlyreduced through use of a common central facility.

The earliest subsea wells were completedfrom semisubmersible drilling rigs with the help ofdivers who directed the equipment into place andopened the valves. Today, subsea completions canbe too deep for divers, so the production equip-ment is monitored and manipulated by remotelyoperated vehicles (ROVs). The simple wellheadand pipeline arrangement has expanded toencompass multiple wellheads connected to amanifold by flowlines, then to a floating produc-

tion system, neighboring platform or shore-basedfacility (above right). Groups of manifolds con-nected to central subsea hubs maximize areal cov-erage of the reservoir. The tieback distancebetween the subsea completion and its platformconnection has increased from a few hundred feetor meters to a record 68 miles [109 km], held bythe Mensa field in the Gulf of Mexico.3

4 Oilfield Review

> A subsea production tree, with flowline connecting to a surface facility.

> Multiple trees. A group of five subsea production trees is linked to a manifold, where flow is collected at a single station before continuing to surface. A second group of five subsea water-injection wellsis in the background.

Winter 1999/2000 5

More and more of the operations originallyperformed at surface are moving to the seafloor.Today’s subsea technology covers a wide rangeof equipment and activities: guidewires for low-ering equipment to the seafloor; Christmas, orproduction, trees; blowout preventers (BOPs);intervention and test trees; manifolds; templates;ROVs; flowlines; risers; control systems; electri-cal power distribution systems; fluid pumpingand metering; and water separation and reinjec-tion. One futuristic vision even depicts a seafloordrilling rig.4

The first subsea production tree was installedin 1961 in a Shell well in the Gulf of Mexico.5

Within 36 years, 1000 wells had been completedsubsea. Industry champions predict that complet-ing the next 1000 will take only another fiveyears, and that expansion will continue at around10% per year for the next 20 years.

In some areas, such as the Gulf of Mexico andoffshore Brazil, expansion will require pushingthe frontiers of depth-limited technology. Onlytwo wells in the world have been completed sub-sea at greater than a 5000-ft [1524-m] waterdepth. Increases in the number of subsea com-pletions are projected for all depths, but the moststriking will be for the ultradeep (above).6

In other areas, the North Sea in particular,growth is evident in the increasing number ofsubsea completions per project. Norsk Hydro isplanning to develop the Troll field with more than100 subsea wells tied back to a floating produc-tion system.

The subsea environment poses a set of tech-nological challenges unlike anything that the sur-face can present, and more than can be coveredhere. This article reviews the task of completinga subsea well and explains the workings of theequipment that controls access to the wellthrough every stage of its existence, from explo-ration, appraisal and completion to interventionand abandonment.

Why Subsea?Describing the full process behind choosing onedeepwater development strategy over another isalso beyond the scope of this article, but a briefoverview will help set the background. As in theplanning of any asset development, the decision-making process attempts to maximize assetvalue and minimize costs without compromisingsafety and reliability. The cost analysis focuseson capital expenditures and operating expenses,and also includes risk, or the potential costs ofunforeseen events.

The conditions driving these costs are numer-ous and interrelated, and include all the reser-voir-related factors usually considered inland-based development decisions, plus thosearising from the complexities of the offshoreenvironment. An abbreviated list includes exist-ing infrastructure, water depth, weather and cur-rents, seabed conditions, cost of constructionand decommissioning of permanent structures,time to first production, equipment reliability,well accessibility for future monitoring or inter-vention, and flow assurance—the ability to keepfluids flowing in the lines.

Certain of these conditions pose awesomechallenges for any offshore development, andpresent strong arguments for subsea completioninstead of or combined with other options suchas semisubmersibles, tension-leg platforms, dry-tree units, and floating production, storage and

offloading systems (FPSOs). Distance from infras-tructure is a key determinant in opting for a sub-sea completion. Wells drilled close enough toexisting production platforms can be completedsubsea and tied back to the platform. The tiebackdistance is constrained by flow continuity,seafloor stability and currents. With some fixed-platform capital expenditures measured in billions of dollars, maximizing reservoir accessthrough additional subsea wells can increaseproduction while keeping capital and operatingcosts down.

Wells whose produced fluids will be handledby an FPSO vessel are also natural candidatesfor subsea completions, and not only because ofreduced time to production. Often these arewells in locations where water depth andweather make more permanent structuresimpractical or uneconomical. Other options inthese environments are either the dry-tree unit,sometimes called a spar, which is a buoyant ver-tical cylinder, or the tension-leg platform—afloating structure held in place by vertical, ten-sioned tendons connected to the seafloor bypile-secured templates. Both the dry-tree unitand the tension-leg platform support platformfacilities and are anchored to the seafloor. Thelatter techniques have been applied withoutsubsea completions at depths reaching about4500 ft [1372 m], but deeper than that the solu-tion has called for a subsea completion in con-junction with the floating systems.

50 150 250 350 450 600 800 1000 2000 3000

Water depth, m

0

100

200

300

400

500

600

700

OperationalPlanned

Num

ber o

f sub

sea

com

plet

ions

> Number of subsea wells, both operational and planned by 2003, by water depth.

3. Sasanow S: “Mensa Calls for a Meeting of the Minds,”Offshore Engineer 24, no. 7 (July 1997): 20-21.

4. Thomas M and Hayes D: “Delving Deeper,” DeepwaterTechnology, Supplement to Petroleum EngineerInternational 72, no. 5 (May 1999): 32-33, 35-37, 39.

5. Greenberg J: “Global Subsea Well Production Will Double By Year 2002,” Offshore 57, no. 12(December 1997): 58, 60, 80.A Christmas tree is the assembly of casing and tubingheads, valves and chokes that control flow out of a well.

6. Thomas M: “Subsea the Key,” Deepwater Technology,Supplement to Petroleum Engineer International 72, no. 5 (May 1999): 46, 47, 49, 50, 53.

At the water depths in question, runninghydrocarbons through flowlines, valves andpipelines is not an effortless task. The low tem-peratures and high pressures can cause precipi-tation of solids that reduce or completely blockflow. Precipitation of asphaltenes and paraffins isa problem for some reservoir compositions, usu-ally requiring intervention at some stage of welllife. Scale deposits can also impede flow, andneed to be prevented or removed.7 The formationof solid gas hydrates can cause blockages intubulars and flowlines, especially when a water-gas mixture cools while flowing through a long tieback. Prevention techniques includeheating the pipes, separating the gas and waterbefore flowing, and injecting hydrate-formationinhibitors.8 Corrosion is another foe of flow conti-nuity, and can occur when seawater comes incontact with electrically charged pipes.

Access to the well for any tests, intervention,workover or additional data acquisition is a keyconsideration. Traditionally, operators haveselected platform-style solutions when thedevelopment requires postcompletion wellaccess. Platforms house Christmas trees andwell-control equipment on the surface, givingeasier access to introduce tools and modify welloperations. To perform these functions on subseawells requires a vessel or rig, and sometimes amarine riser—a large tube that connects thesubsea well to the vessel and contains thedrillpipe, drilling fluid and rising borehole fluids—and planning for their availability whenthe time comes.

All of this adds up to significant cost. In manycases, the subsea production tree must beremoved. Reconnecting to many subsea wells toperform workovers and recompletions can alsorequire a specially designed intervention system

to control the well and allow other tools to passthrough it down to the level of the reservoir. Thedevelopment of the completion test tree is nowenhancing the accessibility of subsea wells,allowing reliable well control for any imaginableintervention. A full discussion follows in latersections of this article.

Equipment reliability is a major concern for anysubsea installation. Once equipment is attached tothe seafloor, it is expected to remain there for thelife of the well. Some operators remain uncon-vinced about the suitability and reliability of sub-sea systems in ultradeepwater developments.However, more and more operators are gainingconfidence in subsea practice as contractors pro-vide innovative and tested solutions.

Equipment Much of the specialized equipment for subseainstallations is designed, manufactured, posi-tioned and connected by engineering, construc-tion and manufacturing companies. ABB VetcoGray, FMC, Cameron, Kvaerner, Oceaneering,Brown & Root/Rockwater, McDermott, Framoand Coflexip Stena are among the companiesthat supply most of the BOPs, wellheads, tem-plates, production trees, production control sys-tems, tubing hangers, flowlines, umbilicals,ROVs, multiphase meters and pumps, separatorsand power generators. The largest structures,such as manifolds, can weigh 75 tons or more,and can be constructed and transported in modu-lar form and assembled at the seafloor location.

In addition, oilfield service companies andother groups provide special tools and servicesfor the subsea environment. Baker Hughes,Halliburton, Expro, Schlumberger and othershave developed solutions to crucial wellbore-related problems.

One of the key concerns in constructing andoperating a subsea well is maintaining well con-trol at all times. Drilling, completion and subse-quent servicing of subsea wells are typicallyperformed from one of two types of vessel: afloating system that is tethered or anchored tothe seafloor; or one that maintains location overthe well with a dynamic positioning system. Inboth cases, it is critical that the vessel remain inthe proper position, or “on station.” The positioncan be described as the area inside two concen-tric circles centered over the well location on theseafloor. The inner circle represents the limit ofthe preferred zone, and the outer circle repre-sents the maximum acceptable limit before dam-age occurs. The vessel activates thrusters topropel the vessel back to the desired location ifcurrents or other conditions such as weatherhave caused it to move off station, all while continuing the drilling, testing, completion orwell intervention.

However, under extreme conditions, thedynamic positioning system may be unable toremain on station or a situation may arise thatcould endanger the vessel. System problemscould include the failure of the thruster system orloss of some anchoring lines, causing the vesselto drift off station. Other situations could includesevere weather or collisions with icebergs orother vessels. Under such conditions, the dynam-ically positioned vessel would drive off station.

All these cases would require disconnectingthe landing string and riser from the well. Oncethe decision to disconnect from the well is made,industry best practices for operation in deepwater with dynamically positioned vesselsrequire that the complete process be achievedwithin 40 to 60 seconds, depending on the condi-tions and systems used. However, prior to dis-connecting from the well and in a separateprocess that itself takes 10 to 15 seconds, allflow from the well must be controlled and nohydrocarbons must enter the sea. Both ends ofthe disconnected conduit must be sealed. Andonce the hazard clears and operation becomessafe again, connection to the well can bereestablished to resume the operation.

The tools that have been developed bySchlumberger and other companies to performthese tasks are called subsea completion andtest trees. They are not permanently fixed to theseafloor as are the production trees, but aredeployed inside the marine riser by a landingstring when needed, run through the BOP stack,

6 Oilfield Review

Schlumberger has designed a series of trees for subsea

operations, testing, completion and intervention. Combinations

of inside and outside tool diameters, pressure and temperature

ratings and control systems are designed to suit a variety of

subsea completion and well-testing applications as well as

water-depth and wellbore conditions.

> A subsea completion and test tree and subsea blowout preventer (BOP) configuration. The completionand test tree fits inside the BOP to control a live well.

Blowoutpreventer

Subseacompletion

and test tree

7. Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson Aand King G: “Fighting Scale—Removal and Prevention,”Oilfield Review 11, no. 3 (Autumn 1999): 31-45.

8. For more on gas-hydrate inhibition: Brandt et al, reference 1: 11-12.

Winter 1999/2000 7

connected to the production tree tubing hangerand then retrieved (right). The tools combine twomain features: the control-system portion of thetool transmits information between the surfaceand the tool and facilitates the activation of thevalves and latches. The valves and latches per-form the connection, flow control, disconnectionand reconnection with the seafloor tree.

Schlumberger has designed a series of treesfor subsea operations, testing, completion andintervention. Combinations of inside and outsidetool diameters, pressure and temperature ratingsand control systems are designed to suit a vari-ety of subsea completion and well-testing appli-cations as well as water-depth and wellboreconditions. For well testing, the smaller diameterSenTREE3 system is used. The SenTREE3 toolhas a 3-in. inside diameter and ratings of 15,000psi [103.4 MPa], and 350°F [177°C]. For comple-tion and intervention, the SenTREE7 system isdesigned with a 73⁄8-in. internal diameter and has10,000 psi [68.9 MPa] and 325°F [163°C] ratingscapable of operating in water depths up to10,000 ft. A chemical-injection line allows addi-tives to be introduced to the well to prevent cor-rosion or hydrate formation.

Each tool’s control system is engineeredaccording to the operator’s requirements. Thetime available for disconnection depends on eachvessel’s dynamic positioning system capabilities,water depth, expected currents and waveheights, and a hazardous operations analysis. TheSenTREE tools are designed to unlatch under fulltension and at an angle greater than can be phys-ically achieved in the BOP stack, to ensure thatcontrolled unlatching is possible in all conditions.In water depths to 2000 ft [610 m], under mildconditions and from a tethered or moored vessel,the time can be up to 120 seconds. The time islonger because the vessel is anchored and doesnot rely on dynamic positioning to stay in place. Inthese cases, the control system usually has adirect hydraulic design. The signal to disconnectis sent through hydraulic lines to solenoid valvesin the tool’s control system that hydraulically acti-vate the tool valves. Due to the behavior of thefluid and the control lines, the time required forthe shutoff signal to travel to the subsea toolincreases with depth. One method for minimizingthis additional time in water depths up to 4000 ft[1219 m] is to enhance the system through use ofpressure accumulators in the subsea hydraulics.

At greater water depths, or in operations froma dynamically positioned vessel, disconnectionmust be achieved in 15 seconds or less. Ahydraulic system alone, over the distanceinvolved, functions too slowly for this, but thecombination of an electrical and hydraulic systemallows a fast electrical signal to activate thehydraulically controlled disconnection and flowshutoff. These systems are known as electrohy-draulic. For the SenTREE3 system, the surface sys-tem sends a direct electric signal on an electricalcable to the three solenoid valves of the downholecontrol system. These valves control the threefunctions of the SenTREE3 tool, which are to closeshutoff valves, vent pressure and unlatch.

The SenTREE7 multiplex control system, onthe other hand, performs 24 functions. Theseinclude opening and closing four valves, latchingand unlatching two tools, locking and unlockingthe tubing hanger, injecting chemicals and moni-toring temperature and pressure (right andbelow). The system is too complicated to operateby direct electrical signal, so a multiplexed signalis sent down a logging cable, then interpreted bya subsea electronics module in the control sys-tem, which in turn activates the tool functions. Inaddition, the electrical system telemeters feed-back on the pressure, temperature, status of thevalves, and other parameters as required, provid-ing two-way communication between tool andsurface. The Schlumberger multiplexed controlsystem is the fastest proven method available.

The shutoff system comprises a ball valve,flapper valves and a latch. A tubing-hanger run-ning tool (THRT) completes the system. A slickjoint separates the various valves and latches tomatch the spacing of the rams of any subsea BOP

8 Oilfield Review

> Inside the SenTREE7 system. Theelectronics module (above) interpretsmultiplexed signals sent from the surface to control tool functions.Hydraulic lines (left) transmit the signals to the tool’s valves and latches.

Winter 1999/2000 9

configuration so the rams can close in the case ofa blowout (below). The valves are specified to holdpressures exerted from inside or outside the sys-tem. To ensure fluid isolation, the valves operatein order: first, the ball then lower flapper valvesshut off fluid rising from the well; second, theretainer valve above the latch closes to containfluids in the pipe leading to the surface; third, thesmall amount of fluid trapped between the twovalves is bled off into the marine riser; finally thelatch disconnects the upper section, which can bepulled clear of the BOP stack. If the riser is goingto be disconnected at the same time, the BOPblind rams are then closed and the drilling riser isdisconnected. The vessel then can move off loca-tion leaving the well under control. The design ofa subsea completion and test tree centers on the

ability to perform a controlled disconnection—anevent that both operator and service companyhope will never happen, but must have the capa-bility to manage should it occur.

The design and manufacturing process forcompletion and test trees is quite different fromthat of other oilfield service tools. Other oilfieldservice tools, such as wireline or logging-while-drilling tools, are typically designed by servicecompanies to be used hundreds of times in manywells and to suit a wide variety of conditions.Subsea completion and test trees consist of stan-dard modules, but must be adapted to suit pro-ject specifications driven by BOP dimensions,shear capability and tubing-hanger systemdimensions, all according to a tightly timeddevelopment and delivery contract.

Spanner joint

Retainer valveBleedoff valve

Shear sub

Latch assembly

Valve assembly

Slick joint

Adjustablefluted hanger

Riser

Hydril

Shear rams

Blind rams

Pipe rams

Pipe rams

BOP stack

SenTREE3 tool

SenTREE series of subsea test and completion tools. The SenTREE3(left) and SenTREE7 (right) toolshave similar design, with valves and latches to shut off fluid flow and disconnect from the well in acontrolled operation. The SenTREE3tool (yellow) is displayed inside aBOP stack (green). The componentsof the SenTREE7 system are labeled in order of their activation in theevent of a disconnection.

Lubricator valve

Control system

Bleedoff valve

Retainer valve

Latch connector

Flapper valve

Ball valve

4

2

3

5

1

SenTREE7 tool

>

Multiple vendors participate in building dif-ferent components of a subsea installation, andeach component must fit and work with others onschedule. Delays in tool availability mean delaysin production. The tools themselves are physi-cally colossal (above). Even the largest wirelinetools fit inside. The substantial dimensions andweight of this equipment require special han-dling equipment and cranes for moving andmanipulation. Tool operation, handling and main-tenance are usually carried out by locations thatalso handle well-testing equipment.

Each completion and test tree must be adaptedto fit a specific subsea production tree and BOPcombination, of which it seems no two are alike.

The first production trees were mainly “dual-bore” type trees, with a production bore and sep-arate annulus bore passing vertically through thetree and with valves oriented vertically. Therewere also a number of concentric-bore treedesigns in which the annulus could not beaccessed.9 Both the dual-bore with separate bores

and the concentric-bore trees are sometimescalled vertical trees by some manufacturers.

A disadvantage of this type of tree is that it is installed on top of the tubing hanger, sothat if the tubing must be pulled for a workover,the production tree—often a 30-ton item—must be removed. In some cases, this may alsoinvolve the removal of umbilicals or evenpipeline connections.

In 1992 a different style of production tree,the horizontal tree, was introduced. In the hori-zontal tree, the production and annulus boresdivert out the sides of the tree and the valves areoriented horizontally. These are sometimescalled side-valve or spool trees. Since the tubingis landed inside a horizontal tree, the tubing canbe accessed or pulled without moving the tree,making intervention much easier. Each type ofproduction tree has a different arrangement withthe BOP, wellhead and tubing hanger, and sorequires its own completion and test tree.

The unique design and the union of electricaland hydraulic methods in the control systemmake the Schlumberger SenTREE7 subsea com-pletion and test tree highly versatile and adapt-able to the needs of the project at hand (nextpage). The subsea completion and test tree iscustom-engineered to fit inside a BOP with anyram spacing and to interface with any tubing-hanger running tool.

10 Oilfield Review

Certificates from Det Norske Veritasissued when modulespass their factoryacceptance test, andGary Rytlewski, subseachief engineer at theSchlumberger ReservoirCompletions center.

> A tool as big as the team. The SenTREE engineering team at the Schlumberger Reservoir Completions center in Rosharon, Texas, USA accentuates the large scale of the SenTREE7 tool.

9. Richborg MA and Winter KA: “Subsea Trees andWellheads: The Basics,” Offshore 58, no. 12 (December 1998): 49, 51, 53, 55, 57.

>

Winter 1999/2000 11

Tool ReliabilityThe primary consideration in selecting a subsea completion and test tree is reliability.Schlumberger ensures reliability of completionand test trees through meticulous, systematictesting. Every component of every tool undergoestests with multiple levels of scrutiny.

The first formal test is the factory acceptancetest (FAT), in which individual modules are testedin-house. The test is conducted in the presence

of a representative from Det Norske Veritas whowitnesses the test and reviews the calculationpackage that shows how that module wasdesigned to work (previous page, bottom).

However, calculations alone do not prove thata tool will function under the extreme conditionsof the subsea environment. Operators need morethan numerical computations when the safety ofpersonnel, equipment and the environment is at

stake. The cost of deploying a substandard sub-sea tool at current rig day rates—a day or moreto run the tool to depth, a few hours to discover itis malfunctioning, and another day or two to bringit back to surface—can reach the million-dollarmark, not counting any repairs. Reliability of othertypes of equipment can be proved in laboratorypressure vessels, but testing a subsea completiontree in a pressure vessel is not an easy task. For

>Engineers assembling a SenTREE7 tool for testing at the Schlumberger Reservoir Completions center.

this purpose, the Schlumberger ReservoirCompletions group designed and constructed anoversized high-pressure test facility (above).

The hyperbaric test facility at Rosharon, Texas,USA was constructed by excavating a 35-ft [11-m]deep pit and creating a 19-in. [48-cm] inner-diam-eter hole to hold an entire completion tree at con-ditions equivalent to those at 10,000-ft waterdepth. Here, any subsea pressure scenario can becreated to match conditions expected for any joband prove that the tool will function properly.

Qualification tests ensure that modules com-ply with specific industry standards of functionand performance, such as those established by

the American Petroleum Institute (API). For exam-ple, any number of API standards specify that amodule must perform at a given temperature,pressure and flow rate, with various fluids, for agiven length of time. These tests are conductedby the Southwest Research Institute in SanAntonio, Texas, according to industry benchmarksthat other subsea equipment must also meet.

Another test that requires third-party involve-ment is the system integration test (SIT) at whichall components from all vendors are assembledin a simulation of a real subsea operation. Theclient is usually present to witness the integrated

test. Typical equipment and services present atthe SIT are the subsea production tree, manifold,flexible and hard flowlines, umbilical control,SenTREE7 subsea completion test tree and con-trol system, tubing-hanger running tool, tubinghanger, slickline unit, dummy ROV, cranes and allthe expected field personnel. In some cases, theconnectors for permanent monitoring systemsand the associated test equipment are also partof the SIT. Any interface between the SenTREE7tool or tubing-hanger running tool and an intelli-gent or advanced completion would be incorpo-rated in the SIT, thus helping eliminate potential

12 Oilfield Review

5000-psiexternal pressureBelow valve zone

Above valve zone

8x control functions

SenTREE7test tree

Latch system tolock in tubing-hanger running tooland tubing hanger

> Massive in-ground high-pressure laboratory for proving subsea tool reliability, with ground-level wellhead(insert). Conditions can be created tomatch those expected for any subseainstallation down to 10,000-ft water depth.

Winter 1999/2000 13

costly offshore interface problems. This approachensures that the equipment will work togetherproperly in the field.

The following sections include field examplesthat demonstrate the roles completion and testtrees play in the different phases of well life,from exploration and completion to interventionand abandonment.

Well TestingIn the exploration stage of a well, after a potentialpay zone is discovered, a well test is conducted toevaluate the production and flow capabilities ofthe well. To test a subsea well, a drillstem test(DST) string is run through the BOP. A typical DSTstring consists of perforating guns, gauges, agauge carrier with surface readout capabilities, aretrievable packer and a test-valve tool. This isconnected by tubing up to the seabed, then to aretrievable well-control test tree set in the BOP toensure that disconnection, if required, is done in acontrolled way. Reservoir fluids flow past the DST

gauges at the reservoir level where pressure andtemperature are detected, then flow through thetubing and test tree, and finally to the surface.

In 1974, when Flopetrol-Johnston Schlumbergerintroduced the first subsea test called the E-Z Treetool, testing operations from a floating vesselwere made possible with the required level ofsafety. Since then, the technology has evolvedand other companies have developed relatedtools. Halliburton and Expro now offer similartest trees and services, and Schlumberger hasdeveloped the SenTREE3 test tree.

In one subsea testing job for Chevron, the controlled disconnect ability of the SenTREE3system was confirmed under severe weatherconditions. The North Sea well was at a waterdepth of 380 ft [116 m]. The SenTREE3 tool wasequipped with a hydraulic control system. Theheavy-oil test was conducted with an electricsubmersible pump and a drillstem test tool.Weather conditions deteriorated until the aver-age heave reached 15 ft [4.6 m]. At this time, the

operator decided to halt the test and unlatch. Theshutoff valves were activated and the tool wasunlatched and drawn up (below left). The riserwas disconnected and the vessel moved off.

By the time the weather calmed down, thewell test was cut short and the primary objectivewas then to relatch and retrieve the drillstem testtool. The reconnection was performed success-fully and the DST was recovered to surface.

Another example of subsea testing successcomes from the Barden field in the NorwegianNorth Sea operated by a consortium consistingof Norsk Hydro, BP, Shell, Statoil and SagaPetroleum. Early in 1998, the operators decidedto evaluate the new discovery with theSenTREE3 tool and were the first in the world touse the Schlumberger electrohydraulic controlmodule (below). The dynamically positionedOcean Alliance maintained position in the 857-m[2812-ft] deep rough waters. With this combina-tion of potentially rough seas and moderatedepth, the ability to disconnect quickly is even

> Emergency disconnect of SenTREE3 system during a well test for Chevron.The hydraulic control system unlatched the subsea test tree when weatherconditions became hazardous, and successfully reconnected to retrieve the test tree and drillstem test tool once the weather moderated.

> The SenTREE3 tool with electrohydrauliccontrol used for testing the Barden field inthe Norwegian North Sea.

more critical than in deeper water, because theangle of the riser relative to vertical changesmore quickly as the vessel moves off station,and the maximum feasible unlatch angle isreached sooner.

Fortunately, the weather remained temperatethroughout the full seven days of the well test. Apressure and temperature sub inside theSenTREE3 tool monitored flowing conditions toassist in the prevention of hydrates. Reservoirfluids flowed through the IRIS Intelligent RemoteImplementation System test string. The produced

liquid hydrocarbons were flared with the newEverGreen burner that generates no smoke orsolid fallout.

In the three years since its introduction, thisnew subsea testing technology has spread toother exploration provinces. Two other well testshave been conducted with the SenTREE3 toolplus electrohydraulic control system—one off-shore Brazil, the other offshore Nigeria. Almost300 other jobs have been run offshore Brazil,West Africa, Australia, Indonesia and in the Gulfof Mexico with the SenTREE3 test tree and thehydraulic or enhanced hydraulic control systems.

CompletionThe operations described so far pertain to subseaexploration and appraisal wells with temporarycompletions: after testing, the packer, test stringand tubing are pulled and the BOP is left in control of the hole for either abandonment orsidetrack operations. Installing a permanentcompletion, or string of production tubing, is per-formed in the development phase when produc-tion wells are drilled and completed or when anexisting well is recompleted. The basic processof completing a subsea well with a horizontalproduction tree can be described as a series offive steps, with a number of subtasks within thefive broad categories:

14 Oilfield Review

1 2 3 4

5. Run subsea horizontal tree. 6. Land the tree, lock connector, test seals and function valves with ROV. Establish guidewires and release tree-running tool. 7. Run BOP stack onto horizontal tree, lock connector, run BOP test tool and test, function-test tree. 8. Retrieve suspension packer, remove wearbushing fromtree, make up SenTREE7 system, rack back.

5 6 7 8

13 3/8-in.casing

Suspensionpacker

10 3/4 by 9 5/8-in.casing

> Subsea completion sequence. 1. Complete drilling and install the suspension packer. 2. Retrieve the drilling riser and BOP stack, move rig off. 3. Retrieve drilling guidebase with ROV assistance. 4. Run the production flow base and latch on 30-in. wellhead housing.

Winter 1999/2000 15

Well suspension—Suspend flow from thewell with kill fluid; run plugs to shut off flow;retrieve the riser and BOP.

Production tree installation—Install the horizontal tree; rerun the drilling BOP; recoverplugs and temporary suspension string.

Completion—Change to completion fluid;condition the well prior to running completion;run the completion with production equipmentand the subsea completion and test tool.

Installation and intervention—Close rams;land off and test hanger; set and test packer;underbalance the well; perforate; clean up flow;pull out the landing string.

Isolation and production preparation—Runand set hanger plug; open rams; unlatch tubing-hanger running tool (THRT); pull THRT out of hole

with landing string. Run internal tree cap; run andset internal tree cap plug.10 Unlatch THRT frominternal tree cap; recover landing string; recoverBOP and riser.

Two oilfield service companies, Expro andSchlumberger, offer tools and services for com-pleting large-bore, horizontal-tree subsea wells.ABB Vetco Gray, an engineering company thatalready supplies tubing hangers, is activelydeveloping capability to offer completion ser-vices also. As service providers gain experiencewith and compile success stories about subseacompletions with horizontal trees, operators willlearn about the advantages the newer trees offerin terms of ease of completion and intervention.

Late in 1999, Shell in Sarawak, Malaysia real-ized considerable savings by advancing quickly

from exploration to production using an “off-the-shelf” horizontal subsea tree—the company’sfirst horizontal tree. Using the SenTREE7 com-pletion tree, they successfully completed thesubsea well 12 days ahead of schedule without aminute of downtime. Schlumberger becameactive in the earliest planning stages of the project. This early involvement ensured that theproject would proceed as smoothly as possible.

The completion proceeded in a series of stepsbeginning with the termination of drilling andcontinuing through landing the production tree,running the completion string with the SenTREE7tool, and tying into a well-test package (previouspage, above and next page, top).

1413 1615

1211

7-in.production

liner

Perforatinggun

13. Carry out production test, acid stimulation and multirate test. 14. Unlatch THRT and retrieve landing string and SenTREE7 tool. Rig down production testpackage and flowhead. 15. Run internal tree cap. 16. ROV closes tree valves. Retrieve THRT and landing string.

(continued on page 16)

10. A tree cap is a cover that seals the vertical conduits in asubsea production tree.

9

7 5/8-in.premium-thread

chrome tubing

7-in. polish borereceptacle (PBR)

with seal units

9 5/8 by 7-in.permanentproduction

packer

10

9. Run completion string, make up tubing-hanger running tool (THRT) and SenTREE7 system on tubing hanger, run landing string with umbilical, make up surface control head to landing string. 10. Land hanger in production tree and test seals. Rig up wireline and retrieve straddle sleeve. Run seat protectors.Circulate tubing to potable water for drawdown. Set wireline plug, test string and set packer. 11. Rig up production test package. Rig up electric wireline and lubricator. 12. Run guns, correlate and perforate well.

1817 19 20

By mid-1999 Texaco had set a record for deep-water subsea completions in their Gulf of MexicoGemini field (below). The enhanced directhydraulic SenTREE7 subsea completion treeassisted in the completion process of three subseawells in 3400 ft [1037 m] of water, at the time aworldwide industry record for this type of subseacompletion system. The enhanced direct hydraulicSenTREE7 system helped run the 5-in. completionstring along with a Cameron tubing hanger on 7-in., 32-lbm/ft [14.5-kg/m] landing string. Thecompletions were performed from the DiamondOffshore Ocean Star, an anchored vessel, and theenhanced hydraulic control system provided the

requisite 120-sec response time to control thewell and disconnect the landing string if required.

After the completions, surface well testswere performed from the anchored vessel. Thefirst well was flowed back to the DiamondOffshore Ocean Star for a total of 65 hours, witha final gas rate of 80 MMscf/D [2.2 million m3/d],condensate at 1500 bbl/day [238 m3/d] and waterat 200 bbl/day [32 m3/d]. Methyl alcohol wascontinually injected at the SenTREE7 chemical-injection line to prevent formation of hydratesduring the flowback period. The SenTREE7 toolwas also used to facilitate the installation of theinternal tree cap. Schlumberger also provided

surface well test equipment and services andsand-detection equipment during well cleanup.All services, including SenTREE7 operation, wereperformed with 100% uptime.

Since then the water-depth record has beenbroken, again by the SenTREE7 tool, in anotherGulf of Mexico field. Late in 1999, a Schlumbergercompletion and test tree operated from ananchored vessel as before, but this time in waterdepths of 4650 ft [1417 m]. The record was setduring completion of a five-well developmentusing a tool system similar to the one deployed inthe Gemini field: the enhanced direct control sys-tem assured a 120-sec response time.

16 Oilfield Review

> Gemini field subsea development. Three Texaco subsea wells in the Gulf of Mexico were completedusing the SenTREE7 system from an anchored vessel.

> Subsea completion sequence (continued). 17. Retrieve BOP stack, retrieve guidewires. 18. Install debris cap, deploy telescopic legs. 19. Suspend well. 20. Tie in to pipeline for production.

Winter 1999/2000 17

Completions of this nature have been per-formed on wells in Africa, the Gulf of Mexico andthe UK, and more are being planned for the year2000. After the exceptional experience in theGemini field, Texaco has selected Schlumbergerfor completions services in 15 subsea wells in itsNorth Sea Captain field. And more multiwell con-tract arrangements have been made with majoroil companies operating in the Gulf of Mexico.

In particular, BP Amoco has signed a three-year multiwell contract with Schlumberger forsubsea completions services in its Gulf of Mexicofields. Two of these reach water depths of 7000 ft[2134 m]. These wells will be completed fromEnterprise, a dynamically positioned drillship,and so will require the multiplexed deepwatercontrol system that provides a 15-second con-trolled disconnect. The entire multiplex systemhas already completed a rigorous qualificationtest and met stringent BP Amoco requirements,including the 15-second disconnect time. BPAmoco purchased a surface well-test packagethat was installed on the Enterprise for use as awell test and early production facility.11

Schlumberger well intervention group developedthe subsea intervention lubricator (SIL). The SIL isdesigned to be deployed and operated from asuitably equipped dynamically positioned vesseland permits wireline or coiled tubing access tolive subsea wells without the requirement of aconventional BOP stack and marine riser.Wireline techniques have limited application inthe hundreds of subsea wells that are highlydeviated or horizontal. An intervention systemmust be able to convey tools and fluids in high-angle wells. Coiled tubing often offers thesecapabilities.

At the end of 1997, the world’s first suchcoiled tubing intervention was carried out fromthe CSO Seawell on the Gannet field for Shell inthe North Sea. Representatives from theSchlumberger well intervention services group,Dowell, Coflexip Stena Offshore and ShellSubsea Well Engineering and UnderwaterEngineering together assessed the risks associ-ated with the development of the system. A cus-tom-built lifting and shipping frame was installedon the CSO Seawell to keep the riser in tensionand deploy the coiled tubing. The system was

InterventionMost wells require some kind of intervention dur-ing their life span. Interventions—installing orservicing subsurface surface-control valves,changing gas-lift valves, production logging,pulling failed tubing, removing scale or paraffins,perforating new sections, squeezing cement intoperforations to shut off water flow—all canextend the productive life of a well. Some com-panies claim that more than half their productioncomes from subsea wells, and they will not tol-erate reduced production that can be amelioratedthrough intervention.12

Intervention can be and has been accom-plished with a drilling rig and marine riser, butreturning to a subsea well using this approach isan expensive proposition. This has led the indus-try to seek more cost-effective methods for subsea intervention.

Subsea well intervention services ofSchlumberger, together with Coflexip StenaOffshore (CSO), have devised a cost-effectivealternative for light well intervention—interven-tion that can be run through tubing. CoflexipStena Offshore built the specially designeddynamically positioned monohull vessels, CSO Seawell and CSO Wellservicer. The

11. For more on early production systems: Baustad T,Courtin G, Davies T, Kenison R, Turnbull J, Gray B, Jalali Y, Remondet J-C, Hjelmsmark L, Oldfield T, Romano C, Saier R and Rannestad G: “Cutting Risk,Boosting Cash Flow and Developing Marginal Fields,”Oilfield Review 8, no. 4 (Winter 1996): 18-31.

12. McGinnis E: “Coiled Tubing Performance UnderliesAdvances in Intervention Vessels,” Offshore 58, no. 2(February 1998): 46-47, 72.

tested first on a suspended wellhead and suc-cessfully performed a series of operations: rou-tine disconnect and reconnect; swivel check;coiled tubing run in hole; logging and circulating;emergency disconnect with 1100 psi [7587 KPa]in riser; and rigging down. On the live Gannetwell, a coiled tubing-conveyed production log-ging test was conducted over four days with nononproductive time (below).

more cost effectively from a dynamically posi-tioned dive-support vessel—a vessel not speciallyequipped for drilling. The two key factors in favorof the new approach with a dive-support vesselwere reduced cost of implementation of thestreamlined task and lower risk due to the short-ened program with minimal hardware recovery.

The abandonment plan maximized efficiencyby executing the operation in two parts—first allwells would be plugged, then all subsea produc-tion trees and wellheads would be recovered.This optimized equipment rental costs and madeit possible for the crew to improve the process byrepeating and learning one type of operation.

The job was performed by the Coflexip StenaOffshore Ltd. CSO Seawell using the subseaintervention lubricator. During the pluggingphase of the plan, the SIL maintained control ofand provided access to each well to carry kill-weight fluid to the open perforations, perforatethe tubing, circulate cement, pressure test theplugs, circulate test dye, perforate casing and cutthe tubing with explosives. In the second phase,the subsea production tree and tubing hangerwere recovered, casing strings were cut explo-sively at least 12 ft [4 m] below the seabed andthe wellhead and casing stumps retrieved. Theoptimized operation took 47 days instead of the81 planned.

To date, 142 subsea production and sus-pended wells encompassing 8 complete produc-tion-field abandonments have been carried out inthe UK continental shelf using the CSO Seawelland the SIL.

For deepwater subsea wells, abandonment ismore involved. Late in 1999, EEX Corporationbegan decommissioning its Cooper field in theGarden Banks area of the Gulf of Mexico—thefirst such project performed at a water depthgreater than 2100 ft [640 m] from a dynamicallypositioned vessel.15 Schlumberger and severalother contractors worked with Cal Dive Inc.through the complex operation that includedremoval of a one-of-a-kind freestanding produc-tion riser, 12-point mooring system, floating pro-duction unit and all the subsea equipment.Schlumberger provided subsea project manage-ment expertise along with coiled tubing, pump-ing, slickline, testing and wireline services.

The first step in decommissioning the fieldwas to kill the seven subsea wells. Once this wasaccomplished, the riser, flowlines, productiontrees and export pipelines were all cleaned and

18 Oilfield Review

CSO Seawell

Rigid riser

Subseainterventionlubricator

Subsea tree

Coiled tubingproduction logging

> Light intervention services on subsea wells from a dynamically positioned monohull vessel using the subsea intervention lubricator. Cost-effective subsea intervention, in the form of coiled tubing-conveyed production logging, was performed in the Gannet field, North Sea.

Since the SIL was developed in 1985, morethan 1166 operational days have been registeredand more than 275 subsea wells have beenentered using the lubricator from the CSOSeawell.13 Key factors in the success of theapproach have been efficiency and cost-effec-tiveness of operations. Compared with opera-tions from a mobile drilling unit, cost savings canrange from 40 to 60%.

AbandonmentAs more provinces mature and prolific fieldsdecline, operators must contend with subseawell abandonment—as challenging a prospectas any other subsea well operation. Well controlmust be maintained at all times, and abandon-ment guidelines must be heeded. These varywith government and regulatory agencies, butgenerally include points regarding the depthbelow the seafloor to which all equipment mustbe cleared, the isolation of producing zones fromeach other, and the isolation of producing zonesand overpressured or potential producing zonesfrom the seabed. Operators want to minimizeexpense at this stage in the life of the well, socost remains a large concern.

One of the first major subsea well-abandon-ment projects carried out in the North Sea was forthe Argyll field in the UK sector.14 In 1975, the field,in 260-ft [79-m] water depth, had been the first tobegin production in the North Sea. By 1992, 35wells had been drilled, of which 18 were com-pleted subsea, and 7 of those had been shut in.Production could not be sustained much longer. Atthat time, conventional abandonment involvedretrieving the completion and setting cementplugs through drillpipe from an anchored ordynamically positioned semisubmersible drillingrig. This process would take 8 to 10 days per well.

An innovative alternative proposal called forsqueezing cement into the productive perforationsthrough the production tubing and cementing thewhole completion into place. This could be accom-plished in about four days per well with the samedrilling rigs as the conventional abandonment, or

Winter 1999/2000 19

flushed. The mooring lines, chains and anchorswere moved off-site, and the seven wells wereplugged and abandoned using a combination ofwireline and specially designed coiled tubingunit. Because the entire abandonment operationwas conducted from the Uncle John, a dynami-cally positioned semisubmersible, the systemalso used an emergency disconnect package.After the wells were plugged, the subsea treesand remote templates were retrieved. The flow-lines and export lines were then filled withtreated salt water and sealed. These lines, alongwith the main template, were left in place on theseabed in such a way that, if required, they couldbe used to support future regional development.

What Next for Subsea?Many companies already are experienced withsubsea solutions and others are just beginning tobecome familiar with the advantages and limita-tions. All agree that although the industry hasachieved measurable advances since the firstsubsea well almost 40 years ago, more work hasto be done before subsea technology can beapplied everywhere it is needed.

Nearly all of the current limitations arerelated to the extreme depths and operating con-ditions encountered by subsea wells. One broadcategory of work to be done concerns metallurgy.Embrittlement of metals at subsea temperaturesand pressures causes failures in equipment.Going deeper may require completely new typesof materials.

Another area of investigation addresses risers, moorings and umbilicals. Groups arelooking into assessing induced vibrations ondrilling risers and the possibility of developingpolyester moorings.

Elsewhere, other initiatives have been under-taken. PROCAP2000 in Brazil supports theadvancement of technologies that enable produc-tion from waters to 2000 m [6562 ft] depth. Sinceits inception in 1986, many of the group’s targetshave been reached, but several subsea projectsconcentrating on subsea multiphase flow meter-ing, separation and pumping are continuing.

The Norwegian Deepwater Programme wasformed in 1995 by the deepwater license partici-pants on the Norwegian shelf, including Esso, BPAmoco, Norsk Hydro, Shell, Saga and Statoil. Thegoal was to find cost-effective solutions to deep-water challenges and included acquiring weatherand current data, constructing a regional modelof the seabed and shallow sediments, determin-ing design and operational requirements, andaddressing problems related to flowlines, umbili-cals and multiphase flow.17

These joint efforts have been established notwith just subsea technology in mind, but touncover solutions for exploration and productionin deep water in general. However, many opera-tors are choosing subsea as their long-termdeepwater development concept. By some esti-mates, 20% of the global capital investments inoffshore field developments are in subsea facili-ties and completions.18 This percentage is likelyto rise, especially as subsea equipment contin-ues to prove reliable, flow-assurance problemsare solved and operators gain confidence in sub-sea practice. —LS

One of the ways the industry is looking forinnovation is through consortia, initiatives andjoint efforts. One of these, DeepStar, is a group ofGulf of Mexico participants from 22 oil companiesand 40 vendors and contractors.16 The oil compa-nies have specified areas in which new deepwa-ter solutions must be found. First on their list isflow assurance. Paraffins and hydrates are themain causes of flow blockage in long tiebacks. Ifways could be found to combat their deposition,longer tiebacks could be possible and economicthresholds could be lowered, allowing develop-ment of reserves that are currently marginal.

Several companies are working on solutionsto these problems. Some are proposing and try-ing methods that attempt to unclog flowlineswith coiled tubing-conveyed tools. Others aretesting the feasibility of heating pipe to controlparaffin and hydrate formation. In addition, theDeepStar organization has begun construction ofa field-scale test facility in Wyoming, USA. The5-mile [8-km] flow loop will be used to validatehydrate-prediction software and multiphase flowsimulators, test new hydrate inhibitors, observethe initiation of hydrate plugs, evaluate sensorsand understand paraffin deposition. Much morework is needed to ensure that subsea wells andlong tiebacks can sustain flow.

As more provinces mature and prolific fields decline, operators

must contend with subsea well abandonment—as challenging

a prospect as any other subsea well operation. Well control

must be maintained at all times, and abandonment guidelines

must be heeded.

13. Stewart H and Medhurst G: “A Decade of Subsea WellIntervention,” presented at World Oil 6th InternationalCoiled Tubing & Well Intervention Conference andExhibition, Houston, Texas, USA, February 9-11, 1998.

14. Prise GJ, Stockwell TP, Leith BF, Pollack RA and Collie IA: “An Innovative Approach to Argyll FieldAbandonment,” paper SPE 26691, presented at the SPE Offshore European Conference, Aberdeen,Scotland, September 7-10, 1993.

15. Furlow W: “Field Abandonment,” Offshore 59, no. 10(October 1999): 114.

16. Silverman S and Bru JG: “Taking the Initiative,”Deepwater Technology, Supplement to PetroleumEngineer International 72, no. 5 (May 1999): 54-56.

17. Silverman and Bru, reference 16.18. Thomas, reference 6.

Nothing lasts forever. To many of us, “forever” isour life span, which can vary widely among indi-viduals. The “permanence” of inanimate objectsalso varies in absolute time and importance. Forexample, commercial communication satellitesare expensive to fabricate, difficult to deploy andgenerally inaccessible for repair, so it is impor-tant that they function properly for a long time.Replacement valves and pacemakers for humanhearts can be replaced or repaired, but not with-out considerable risk to the recipient. Equipmentsent to the remote research stations ofAntarctica is expected to stand up to harsh con-ditions. Buildings, bridges and monuments arealso built to endure, but they have finite life-times. Intelligent completions, which combineproduction monitoring and control, are becomingmore common, and require reliable downholegauges and flow-control valves.1

Downhole equipment in the oil field alsomust stand the test of time. The productive life

of an oil or gas well may be 10 or more years, so“permanent” downhole equipment must last atleast that long to satisfy operators’ expectations.Because it is impractical to conduct equipmenttests of such long duration, reliability engineer-ing and failure testing have become mainstays ofthose people who develop permanent monitoringsystems. The result has been an impressive reliability track record for permanent monitoringinstallations worldwide.

In this article, we begin by examining thechallenges in permanent monitoring. Next, weconsider how engineers develop robust perma-nent gauges to provide a continuous stream ofdata for the life of a well. Finally, we presentexamples that demonstrate how the use of per-manent gauges adds value by helping to optimizeproduction and forewarning operators of prob-lems so that preventive or corrective action canbe taken.

FloWatcher, NODAL, PQG (Permanent Quartz Gauge),PressureWatch, PumpWatcher, Sapphire and WellWatcherare marks of Schlumberger.1. For more on flow-control aspects of intelligent

completions: Algeroy J, Morris AJ, Stracke M, Auzerais F, Bryant I, Raghuraman B, Rathnasingham R,Davies J, Gai H, Johannessen O, Malde O, Toekje J and Newberry P: “Controlling Reservoirs from Afar,”Oilfield Review 11, no. 3 (Autumn 1999): 18-29.

20 Oilfield Review

Downhole Monitoring: The Story So Far

Joseph EckHouston, Texas, USA

Ufuoma EwheridoJafar MohammedRotimi OgunlowoMobil Producing Nigeria UnlimitedLagos, Nigeria

John FordAmerada Hess CorporationHouston, Texas

Leigh FryShell Offshore, Inc.New Orleans, Louisiana, USA

Stéphane HironLeo OsugoSam SimonianClamart, France

Tony OyewoleLagos, Nigeria

Tony VenerusoRosharon, Texas

For help in preparation of this article, thanks to FrançoisAuzerais, Michel Bérard, Jean-Pierre Delhomme, JosianeMagnoux, Jean-Claude Ostiz and Lorne Simmons, Clamart,France; Larry Bernard and David Lee, Sugar Land, Texas,USA; Richard Dolan and Brad Fowler, Amerada HessCorporation, Houston, Texas; David Rossi and Gerald Smith,Houston, Texas; John Gaskell, Aberdeen, Scotland; andYounes Jalali and Mike Johnson, Rosharon, Texas.We thank Philip Hall, Chief Executive of The Sir HenryRoyce Memorial Foundation, for information about SirHenry Royce’s “bumping test” machine.

Reservoir monitoring requires dependable downhole data-acquisition systems.

Products based on sound reliability engineering and failure testing, essential to

building durable permanent monitoring systems, are responsible for an impressive

track record for permanent gauge installations worldwide. Gauges supply data

useful for both short-term troubleshooting and for long-term development planning.

Winter 1999/2000 21

Challenges in Permanent MonitoringFrom the perspective of reliability, permanentdownhole gauges used in oil and gas wells aresimilar to commercial communication satellites,although other industries, such as the automotiveindustry, confront similar reliability challenges.Each system must endure a long life under harshenvironmental conditions. Once in place, thedevices are not routinely repaired, replaced orrecovered. Parts may never return to surface forlab analysis of what worked and what didn’t; it isdifficult to determine what failed without retriev-ing and examining a malfunctioning device.

A typical approach to these challenges is toinclude redundant components in the hope that if one part fails, its backup will function. Whenused wisely, redundant designs can improve reli-ability significantly. However, in both downholegauges and satellites, redundant componentsoccupy valuable, limited space and consumeprecious power. Common failure modes must beavoided when specifying redundant components.For example, if a particular component is prone to failure in a particular environment, its backuppart should be made from different material sothat it too won’t fail under the same conditions.The annals of aviation include numerous episodesof common-failure-mode disasters. CharlesLindbergh undertook a transatlantic flight in thesingle-engine Spirit of Saint Louis in 1927 onlyafter careful study convinced him that the lack ofbackup systems would not put him at risk.2

In addition to fabricating durable permanentdownhole equipment, engineers and designerswork together to address the complexity ofequipment installation and conditions at thewellsite. Competent field engineers and robustequipment are both essential for reliability. Forexample, it is difficult to maintain a high level ofmanual dexterity for hours at a time in an icydownpour or a fierce wind. It is important for thefield crew to install a monitoring system usingwell-designed installation tools that ensureinstallation consistency, especially in remotelocations. Simplifying the installation process asmuch as possible also improves success rates.Early failure of permanent monitoring systemsdecreases when a well-prepared crew performsthe installation with familiar tools.

Operators have used permanent downholepressure gauges since the 1960s.3 The vast bodyof experience is paying off in the latest genera-tion of gauges, for which statistically valid relia-bility data are now available. There are nowthousands of gauges deployed worldwide, over800 of which have been installed by Schlumbergersince 1973 (above and next page, top). A signifi-cant increase in installations occurred after anew generation of more reliable gauges wasdeveloped in the early 1990s.

22 Oilfield Review

Metal-to-metal sealedcable head

Hermetically sealedwelded housing

Cable driver andfault-tolerant regulator

Digital pressure,temperature and self-test11

010

Quartz crystal resonatorsto measure temperatureand pressure

Protection bellows

P/T

Pressure connection

Gland radialconnection

Autoclave axialconnection

or

1/4-in. encased cable

> Permanent downhole pressure guage. ThisPQG Permanent Quartz Gauge system measurespressure and temperature using quartz crystalresonators.

1973 First permanentdownhole gauge installationin West Africa, based onwireline logging cable andequipment

Depe

ndab

ility

1975 First pressure andtemperature transmitter ona single wireline cable

1978 First subseainstallations in North Seaand West Africa

1983 First subseainstallation with acousticdata transmission to surface

1986 Fully welded metaltubing-encased permanentdownhole cable

<Schlumberger milestones in permanent monitoring. Incremental improvements in dependability—that is, reliabledelivery of high-quality measurements—of permanent gauges are shown qualitatively by the time line below.

2. http://www.pbs.org/wgbh/amex/lindbergh/timeline/index.html

3. Nestlerode WA: “The Use of Pressure Data FromPermanently Installed Bottom Hole Pressure Gauges,”paper SPE 590, presented at the SPE Rocky MountainJoint Regional Meeting, Denver, Colorado, USA, May 27-28, 1963.

4. For more on permanent downhole pressure gauge hard-ware: Baker A, Gaskell J, Jeffrey J, Thomas A, VenerusoT and Unneland T: “Permanent Monitoring—Looking atLifetime Reservoir Dynamics,” Oilfield Review 7, no. 4(Winter 1995): 32-46.

Winter 1999/2000 23

Dependability, the Sine Qua NonA basic permanent downhole gauge consists ofsensors to measure pressure and temperature,electronics and a housing (previous page, right).4

A mandrel on the production tubing holds thegauge in place. A cable, enclosed in a protectivemetal tube, is clamped onto the tubing. The cable connects the gauge to the wellhead and then to

surface equipment, such as a computer or controlsystem. Because acquiring and transmitting gooddata depend on proper functioning of each part,such systems are only as reliable as their weak-est component.

A complete monitoring and communicationsystem, such as the WellWatcher system, han-dles diverse sensors, including a FloWatcher

sensor to measure flow rate and fluid density, a PumpWatcher sensor to monitor an electricsubmersible pump and a PressureWatch gaugeto measure pressure and temperature (below).Surface sensors measure multiphase flow rateand pressure and detect sand production. Inaddition to surface controls for valves andchokes, there is a computer to gather data, which

Surface sensors and controls Multiphase flow rate Valve and choke control Pressure measurements Sand detection

Permanent downhole sensors FloWatcher sensor to monitor flow rate and density PumpWatcher sensor to monitor electric submersible pump PressureWatch gauges to measure pressure and temperature Host server and database

Data-retrieval andcommunications software

Integratedapplications

> A complete permanent monitoring system for measuring pressure, temperature, flow rate and fluid density downhole. Surface sensors measureflow rate and pressure. A data-retrieval and communications system facilitates data transfer to the office of the end user.

1986 Introduction of quartzcrystal permanent pressure

gauge in subsea well

1990 Fully supported copperconductor in permanent

downhole cable

1993 New generation ofquartz and sapphire crystal

permanent gauges

1994 PQG Permanent QuartzGauge performance substant-

iated by gauge accreditationprogram at BP. Start of long-

term lab testing

1994 FloWatcher installationfor mass flow-rate measurement

are stored at the wellsite or transmitted to theoffice (below).5

Permanent downhole systems must bedependable throughout their lifetimes—theymust be reliable and stable. “Dependability” con-jures different meanings for different people, butis used in this article to refer to the combinationof reliability and stability. “Reliability” in the con-text of downhole gauges refers to proper instal-lation and ongoing delivery of data from thegauge. It can be defined as the probability thatthe gauge will perform as specified without fail-ure for a certain amount of time under therequired environmental conditions.

“Stability” refers to the actual measurement.Measurements from an unstable or excessivelydrifting gauge might prove more troublesome toan oilfield operator than outright failure of the

gauge. It is important to know whether gradualvariation in a measurement with time indicatesan actual change in the reservoir or reflects adrift problem with the measuring device.

To ensure a dependable product, it is essen-tial to maintain strict quality control throughoutthe entire engineering process. Quality is thedegree to which the product conforms to specifi-cations. To truly achieve world-class reliabilityand stability entails systematic product develop-ment and qualification testing, use of qualifiedcomponents and proven design methods, strictaudits and tracking of generic parts, failure analy-ses and consultation with industrial and academicpeers. Reliability and stability cannot be testedinto a product after it is built, but instead must beconsidered throughout the entire process, fromdesign and production to installation.

The Road to ReliabilityDuring the past 10 years, Schlumberger hasenhanced the dependability of its permanentmonitoring systems through improvements inengineering and testing processes, systemdesign, risk analysis, training and installationprocedures (next page, top).6 Like other tools andsystems developed by Schlumberger, permanentgauge development follows a logical sequence ofengineering phases. Dependability concerns areparamount during each phase.

The engineering phase begins with develop-ment of a mission profile, or a verbal descriptionof the technical concept that serves as an engi-neering framework. The mission profile definesthe role of each component and the environmen-tal conditions components will encounter during

24 Oilfield Review

WellWatcheracquisition unit

Sensors

Automaticdata-retrievalserver

Automatic data-retrieval client

Central storage

Central storageconfiguration

Archivingdatabase

ASCII files

Data browser

Data access library

Engineeringoffices

HELIKOPTER SERV

Wellsite Office

> Data flow. Measurements are transmitted from the downhole device through the cable to surface. The surface data-acquisition unit can send data bysatellite to engineering offices, where data are stored in a library for easy access.

Winter 1999/2000 25

their expected lifetime. All components of thesystem are screened and qualified to withstandthe expected conditions. Accelerated destructivetests subject components to conditions muchmore extreme than expected over their lifetime,such as greater mechanical shocks and vibrationsand higher-than-downhole temperatures andpressures. This type of testing helps determinefailure causes and failure modes. Long-term test-ing of the system enables engineers to validatereliability models and quantify measurementstability (below).

A drawback to accelerated testing is that failure can occur simply because of the stressfultest procedure, and the test might not be a goodpredictor of actual performance. It is impossibleto test everything, but it is important to test asmuch as possible to increase confidence that theproduct will perform as required in commercialoperations. Feedback from field engineers is a crit-ically important complement to laboratory testing.

Product engineering

Mission profile and requirementsPrototype product designRisk analysis and test plansComponents qualification testingReliability qualification testingTechnical reviews and auditsSustaining, product improvement

Training and personnel development

Training with development and field engineersWell completions installation trainingPerformance evaluation and growth planTechnique improvement

Project engineering

Reservoir engineering and production requirementsWell completions design and installation planningWell construction, installation and operationProject improvement

Reliability and data qualitymanagement

Collect field track records into databaseAnalyze results and feedback for improvementReview with operators, development and field engineers

>Permanent monitoring system development. From the initial mission profile to failure analysis, collaboration between engineers, field personnel and operators contributes to continual improvements in permanent monitoring systems.

Permanent gauge stability test. This plot of pressure versus time represents testing of a PQG Permanent Quartz Gauge system atelevated pressures and temperatures for morethan two years. The initial test conditions were140ºC [284ºF] and 7000 psi [48.2 Mpa]. Testingwas then accelerated, with the temperatureincreased to the maximum rated temperature of 150ºC [302ºF], and then to 160ºC [320ºF] and170ºC [338ºF], to make the gauge fail. Each time the temperature was increased, there was a brief period of measurement drift before the gauge reached stability. The gauge driftedless than 3 psi/yr [20 kPa/a]. During the test, the gauge performed as expected, but the testcell had to be repaired twice!

5. For a related article on data delivery in this issue: Brown T,Burke T, Kletzky A, Haarstad I, Hensley J, Murchie S,Purdy C and Ramasamy A: “In-Time Data Delivery,”Oilfield Review 11, no. 4 (Winter 1999): 34-55.

6. Veneruso AF, Sharma S, Vachon G, Hiron S, Bussear Tand Jennings S: “Reliability in ICS* IntelligentCompletions Systems: A Systematic Approach fromDesign to Deployment,” paper OTC 8841, presented atthe 1998 Offshore Technology Conference, Houston,Texas, USA, May 4-7, 1998.

010,000

10,005

10,010

10,015

10,020

10,025

10,030

100 200 300 400 500 600 700 800 900

PQGpressure reading

1 year 2 years

Test

cel

l rep

airs

Test

cel

l rep

airs

-3 psi/year drift

0 psi/year drift

Duration of testing, days

Pres

sure

, psi

150°C 160°C 170°C

PQG Stability Test at 10,000 psi

>

Tests for susceptibility to mechanical shockand vibration, such as those expected duringtransport and installation, are also performed.7

These tests are similar in concept to thosedeveloped by Sir Henry Royce, the engineerbehind the success of the Rolls-Royce auto-mobile. By repeatedly bumping the car on anapparatus that simulated bumps in a road, Royce determined which parts of the chassiswere not strong enough and developed betterones (right).8 The changes included replacingrivets with bolts and using a few large boltsrather than many small ones.

In the system-design phase, engineers ensureproper interfacing between the completion components. Communication with completionengineers and third-party vendors has resulted incontinual improvement in downhole cable con-nections and protection of the system.

Both experts and end users provide input dur-ing the development phase, as engineers performsimulations and build mock-ups. Conducted fre-quently, design reviews include field personnel.Design rules have been prepared to address theneed for low stress on components, minimalexternal connections and other concerns.

Once the system is built and is ready forinstallation, a specially trained crew reviewsdetailed installation procedures and projectplans with operations personnel and third-partyvendors. Performance of the field installationcrew plays an important role in system reliability,so formal training programs for both systemdesign engineers and field installation techni-cians are conducted. Whenever possible, systemdesign engineers attempt to simplify installationrequirements because factors such as frigid temperatures, gusty winds and long hours maypresent additional challenges to the crew. Adesign that allows fast, easy installation relievessome of the burden on the field crew and minimizes risk and rig time.

26 Oilfield Review

>Torturing tools. By exposing an automobile chassis to repeated mechanical shocks (top), Sir HenryRoyce observed which parts were prone to failure and built better ones for Roll-Royce, beginningaround the turn of the last century. Today, highly specialized testing machines and accelerated testtechniques developed by Schlumberger verify the endurance of downhole equipment againstmechanical shocks (bottom).

7. Veneruso A, Hiron S, Bhavsar R and Bernard L:“Reliability Qualification Testing for PermanentlyInstalled Wellbore Equipment,” abstract submitted to the2000 SPE Annual Technical Conference and Exhibition, to be held in Dallas, Texas, USA, October 1-4, 2000.

8. We thank Philip Hall for information about the “bumpingtest” machine. Mr. Hall retired from Schlumberger after22 years of service, both in the oilfield and in electronics.He is Chief Executive of The Sir Henry Royce MemorialFoundation, The Hunt House, Paulerspury,Northamptonshire, NN12 7NA, England.

Winter 1999/2000 27

Learning from ExperienceIf a permanent downhole gauge fails, engineersanalyze the circumstances and sometimesattempt to reproduce the failure modes in theengineering center or other testing facility. Failuremechanisms are not random; in most cases thereare underlying causes at work that must beuncovered, such as design problems, faulty mate-rials or improper installation. Schlumberger hasestablished an on-line database to capture dataabout system installations, including detailsabout environmental conditions, to identify anypatterns in failures (right). The database allowsstatistical analysis of the data by region, operator,environmental conditions and other operationalparameters. Careful analysis of the worldwidedatabase increases confidence that the appropri-ate lessons are learned from field experiencesand helps focus efforts on possible areas ofimprovement.

From August 1, 1987, to the present, the per-formance of 712 permanent gauge installationshas been tracked. The oldest system is more than16 years old, having been installed a few yearsbefore the database was established. Analysis of572 new-generation digital technology installa-tions made since their introduction in March1994 indicates that over 90% of thesePressureWatch Quartz and Sapphire systemswere still operating after 2.5 years (below). Theanalysis, based on methods introduced by

> Permanent downhole gauge database. Careful tracking of each system enables analysis ofgauge performance. Comparison of environmental conditions helps teams prepare to installgauges in new locations by learning from past experience in similar areas.

00.0 0.5 2.01.51.0 2.5 3.0 4.0 4.53.5 5.0

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Operational life, years

Surv

ival

pro

babi

lity,

%

Permanent gauge operating life. Since record-keeping began in 1987, Schlumberger has installedmore than 700 permanent gauges worldwide.Analysis of 572 new-generation digital technologyinstallations made since March 1994, shown by the purple line, indicates that over 88% of thesePressureWatch Quartz and Sapphire systemswere still operating after 4 years. The lavendertrend line begins at 97% and decreases by 3% per year, a higher failure rate than that of theactual data. The photograph shows the productionfacilities of the Baldpate field, operated by Amerada Hess.

>

Møltoft, helps reveal the key factors influencingthe reliability of permanent monitoring systems(above right).9 The Møltoft method addresses asystem’s actual operational time rather than itscalendar time, a key advantage when studyingfield installations over a long time period. Themethod helps pinpoint areas for improvement insystem design and deployment.

Operating companies have independentlystudied the reliability of permanent gauges.10

Different manufacturers and operators measureperformance according to their own standards.Schlumberger has chosen to focus on the wholesystem rather than a single component becauseit is vital that the entire system operate properlyand provide usable data.

Downhole to Desktop: Using the DataAfter the equipment has survived the ordeal oftesting and installation, the real challenge beginsonce a permanent monitoring system is placedsecurely in a well. A system that takes a mea-surement every second of the day produces over31 million data points per year. Coping with thevolume of data from permanent monitoring systems is an issue that operators and servicecompanies continue to address.11 Some operatorshave chosen to sample their data at specifictimes or when the change in a measurementexceeds a predetermined threshold. Others sam-ple their data at greater time intervals, such as30 seconds, to reduce data volume.

Once reaching the end user, the data are appliedto two general production issues: reservoirdrainage and well delivery (right). Reservoir-drainage aspects include pressure monitoring,pressure maintenance, material-balance modelsand simulation models. Well-delivery issues,such as skin and permeability, affect productionengineering.

When a well is shut in for maintenance, apressure gauge offers the small-scale equivalentof a pressure buildup test. Subsequent well shut-ins allow engineers to analyze the repeatability

28 Oilfield Review

Reservoir drainage

Application Description

Well delivery

Application Description

Pressure monitoring Static bottomline pressure survey

Pressure maintenance Future development plans (reservoirrepressurization: install injection facilities?)

Real-time fracturing and stimulationoperation monitoring

Appraisal of injection and production profile along the well

Material balance model updating Input data for continuous update andrefinement of material balance model

Well test interpretation and analysis(buildup, drawdown, multirate andinterference well testing)

Reservoir boundaries, well spacingrequirements, interwell pressurecommunication

Water and gas injection monitoring Evaluate degree of pressure support from injector wells

Appraise performance of injection program

Reservoir simulation model refinement and validation

Historical database for pressure history matching

Calibration tool for simulation model

Well test interpretation and analysis(buildup, drawdown, multirate andinterference well testing)

Skin, permeability and average reservoir pressure

Production engineering Input for NODAL analysisProductivity Index (PI) and long-term

variation in PI measurement;generation of water, gas and sandproduction rate correlation as afunction of pressure

Flowing bottomhole pressure survey to determine maximum offtake _

Flow well at optimal pressure abovebubblepoint pressure to avoidliberation of free gas

Complement or corroborate other reservoir monitoring measurements

Corroboration of information provided by innovations such as 4D seismicsurveys, time-lapse well logging

>Typical applications of permanent downhole gauge data. Data from downholegauges can be used to improve both reservoir drainage and well delivery.

Operational time

Accu

mul

ated

failu

res,

%

Flaws(manufacturing and installation related)

Random overload(design related)

”Predictable“ wear-out(design and environment related)

Characterizing performance over time. Even the most reliable permanent gauge canfail and the root cause often is a matter ofspeculation. Production-related or installationflaws account for many early failures. Atintermediate stages, failures occur at a low,relatively steady rate, apparently because ofrandom overloads. After many years of service,failures may occur as components age.

>

Winter 1999/2000 29

of the tests and improve confidence in selectinga reservoir model. If all the wells in a field areshut in, downhole gauges can measure the aver-age reservoir pressure. The average reservoirpressure measured this way is a key componentof decline rate and reserve estimations and aparameter for reservoir simulations.12

In fluid-injection projects, permanent downholepressure gauges can be used to better maintainpressure, displace oil, arrest subsidence and dis-pose of fluids. By monitoring a continuous streamof pressure data, operators can control reservoirperformance by injecting fluids to keep reservoirpressure above bubblepoint pressure to ensureproduction of oil rather than gas. Permanentgauges can also help determine the optimal pro-duction rate when there are concerns about sandproduction or water coning at high flow rates.

Downhole pressure gauges allow engineersto allocate production to specific wells. Knowingthe downhole pressure, the wellhead pressureand the general properties of the produced fluidsallows calculation of the flow rate for a well andcalibration of flow rates with test data. Offshoresatellite fields tied back to platforms and fieldsowned by multiple partners are good candidatesfor this particular application of downhole pres-sure gauges.

In artificial-lift applications, downhole pres-sure gauges help engineers determine how wellthe artificial-lift system is performing. For exam-ple, a prolific, highly permeable, unconsolidatedoil reservoir might have high deliverability, butthe bottomhole pressure of the well might beinadequate to produce the fluid to surface. If anelectric submersible pump or gas-lift system isinstalled in the well, the operator can add adownhole gauge to assess the performance ofthe lift system.

Gauges in ActionThe permanent monitoring applications that fol-low come from widely separated regions withdifferent operational challenges and operatorpriorities. In each case, the operator might mea-sure the value of permanent monitoring systemsin a variety of ways, such as additional barrels ofoil recovered through more efficient reservoirdrainage or delivery from individual wells, or incost savings through decreased well interven-tions. Appraisal of a deep, sour, high-pressure,high-temperature (HPHT) discovery in the MiddleEast presented numerous operational and inter-pretation challenges. Unlike the prolific shallowoil fields nearby, the discovery well producedanomalously high API gravity oil for the regionfrom a fractured carbonate reservoir with limitedmicroporosity. A thick salt layer above the reser-voir complicated interpretation and operations.Nevertheless, the accumulation presented fasci-nating opportunities to evaluate fracture fairwaysbelow structural spillpoints and hydrocarbon self-sourcing in a kerogen-rich reservoir rock.

Data from the initial discovery well were inad-equate to calibrate reservoir simulations or toplan development. A deep appraisal well, drilledover the course of a year with mud weightsexceeding 20 pounds per gallon [2.4 g/cm3], pro-vided core, mud log and wireline log data. Anextended well test generated enough data forengineers to decide how to proceed.

The extremely high formation pressures anduse of kill-weight mud in wellbores meant thatwireline-conveyed pressure measurements werenot possible. Instead, the operator selected aFloWatcher system to measure pressure, temper-ature and flow rate continuously. This installation

was the first use of the FloWatcher system at apressure of 15,000 psi [103.4 Mpa], so advancepreparations were necessary. The wellhead,which had already been procured, was modifiedto allow an exit for the cable. A shed was built toaccommodate surface monitoring equipment.

The permanent monitoring system wassafely installed and an extended well test wasconducted for four months, with oil flowingthrough a 70-km [43.5-mile] flowline. TheFloWatcher system was selected in partbecause pressure measurements at the Venturiinlet and throat allowed determination of theabsolute pressure, the pressure change acrossthe Venturi and the flow rate. Despite arepairable seal failure in the Venturi, it was stillpossible to obtain pressure measurements fromthe pressure gauge, which functioned asexpected throughout the test. Also, the mandreldesign for the system was relatively inexpensive.

The permanent monitoring system enabledengineers to produce at the maximum rate whilemaintaining pressure above the bubblepoint, andto gather the data they needed to formulatedevelopment plans. Given the operational chal-lenges of this particular well and area, theremote location and the importance of gaininguseful data, an extended well test with a perma-nent downhole monitoring system proved to bethe optimal approach.

Permanent downhole monitoring systemshave been used in the Gulf of Mexico for severalyears. Shell Offshore, Inc., has installed perma-nent gauges in each of the 10 wells it operates inthe Enchilada area in the continental Gulf ofMexico (above). The Enchilada area comprisesthin-bedded turbidite reservoir sands located both

>Enchilada field. The Enchilada area includes several blocks in the Garden Banks area offshoreLouisiana, USA. The blocks are 3 miles [4.8 km] long and 3 miles wide.

9. Møltoft J: “Reliability Engineering Based on FieldInformation—the Way Ahead,” Quality and ReliabilityInternational 10, no. 5 (May 1994): 399-409.Møltoft J: “New Methods for the Specification andDetermination of Component Reliability Characteristics,”Quality and Reliability International 7, no. 7 (July 1991):99-105.

10. van Gisbergen SJCHM and Vandeweijer AAH:“Reliability Analysis of Permanent Downhole MonitoringSystems,” paper OTC 10945, presented at the 1999Offshore Technology Conference, Houston, Texas, USA,May 3-6, 1999.

11. A complete discussion of processing and reducing datafrom permanent downhole gauges is beyond the scopeof this article. For one example of how to process data:Athichanagorn S, Horne R and Kikani J: “Processing andInterpretation of Long-Term Data from PermanentDownhole Pressure Gauges,” paper SPE 56419, pre-sented at the SPE Annual Technical Conference andExhibition, Houston, Texas, USA, October 3-6, 1999.

12. Baustad T, Courtin G, Davies T, Kenison R, Turnbull J,Gray B, Jalali Y, Remondet J-C, Hjelmsmark L, Oldfield T,Romano C, Saier R and Rannestad G: “Cutting Risk,Boosting Cash Flow and Developing Marginal Fields,”Oilfield Review 8, no. 4 (Winter 1996): 18-31.

TEXAS

LOUISIANA

Garden Banks

Baldpate

BaldpateNorth

Enchilada

0

0 160 km

100 miles

above and below salt. The first gauge wasinstalled in September 1997, and to date all ofthe gauges continue to operate without failure.

Permanent downhole pressure gauges fulfilltwo major requirements for Shell Offshore: dailyoperations improvements and better long-termreservoir management. In both cases, pressuredata must be accessible to reservoir specialistsin a format they can use efficiently. The systeminstalled by Schlumberger stores the data forsubsequent pressure transient analysis. ShellOffshore retrieves the data from the system anduses its own computer-assisted operations (CAO)system to manage the data stream on a long-term basis.

Shell’s CAO acquisition unit captures surfaceand downhole pressure measurements atapproximately 30-second intervals for trend analy-sis and long-term archiving of pressure data. Inthe past, most decisions about daily operationswere made on the basis of surface pressure ortubing pressure measurements with infrequentdownhole wireline pressure measurements. Adecline in surface pressure could indicate reser-voir depletion or a downhole obstruction, but thisambiguity could not be resolved with surfacedata alone. Now, with both surface and down-hole pressure measurements, it is possible toquickly diagnose production problems. For exam-ple, if both surface and bottomhole pressurecurves track each other on a declining trend, thenthe probable cause is reservoir depletion. On theother hand, if the surface pressure is droppingbut the downhole pressure remains constant orincreases, then the engineer might suspect thatsalt, scale or paraffin is plugging the tubing(right).13 Therefore, engineers for the Enchiladaarea use surface and downhole measurements todiagnose production problems and optimizeremediation treatments.

Permanent downhole pressure gauges areespecially important for effective reservoir man-agement in the Enchilada area and areas like it.Thin-bedded reservoirs, such as turbidite sands,can be difficult to evaluate by wireline methods.Producers want to determine if the reservoir iscontinuous. During the initial development, fewappraisal wells had been drilled and the subsaltlocation of several prospects made it difficult todefine the reservoir geometry and extent.Gathering early reservoir pressure data fromeach well aided development planning. In addi-tion, the long-reach, S-shaped wells in theEnchilada area are expensive to drill and noteasily accessed by wireline methods.Furthermore, the mechanical risk of runningwireline pressure devices into these high-ratewells is unacceptable. Therefore, the perma-nent gauge system allows frequent reservoir

pressure monitoring without mechanical riskand with minimum deferred production.Frequent pressure measurements help optimizeproduction rates, and enhance understanding ofultimate reserve potential.

The Enchilada area example affirms that datafrom permanent gauges are valuable throughoutthe life of the well. Run time is a major concern forShell Offshore because the Enchilada wells areexpected to produce for at least 10 years. The reli-ability and durability of these permanent gaugeshave a direct impact on the asset’s value. The suc-cessful application of permanent monitoring tech-nology convinced Shell to install gauges in twowells on their deepwater Ram-Powell platform,offshore Gulf of Mexico. The second of theseinstallations, a PQG Permanent Quartz Gauge sys-tem set at a depth of 23,723 feet [7230 m], is thedeepest installation by Schlumberger to date.

30 Oilfield Review

Pres

sure

Time

Psurface

Pbhp

Psurface

Pbhp

Pres

sure

Time

Diagnosing production problems. Plots of bothbottomhole, Pbhp, and surface pressure, Psurface,versus time help engineers diagnose productionproblems. In the top example, surface and bottomhole pressures are declining, but thecurves track each other, suggesting reservoirdepletion. In the bottom plot, the surface pressure diverges and drops at a faster ratethan the bottomhole pressure. One possible conclusion is that scale is plugging the production tubing.

>

Winter 1999/2000 31

Complicated deepwater developments, suchas the Baldpate field in Block 260 of the GardenBanks area of the Gulf of Mexico, challenge oper-ating companies (above). The first downholegauge in the Baldpate field was installed inAugust 1998. Seven of eight wells have down-hole gauges. The field is expected to produce for6 to 10 years.

Baldpate field comprises two major Pliocenereservoirs at depths of 15,500 to 17,500 feet[4724 to 5334 m]. Original reservoir pressuresexceeded 13,000 psi [89.63 MPa]. Productionfrom the sands in the Baldpate North area iscommingled in a seventh well. The field reachedpeak production of 58,000 BOPD [9216 m3/d] and230 MMscfg/D [6.5 MMm3/d] by June 1999.

Installation of permanent downhole gauges isparticularly demanding at the well depths andpressures of Baldpate field. Success depends ona thoroughly trained, competent wellsite crew.For example, the crew must avoid potential pit-falls such as damaging the cable and making badsplices. Extensive prejob planning allows theentire team to anticipate problems and work outsolutions before installation. Having many of thesame crew work on every installation buildsexperience and carries lessons learned from onejob to the next.

Amerada Hess Corporation, operator ofBaldpate field, elected to install permanentdownhole pressure gauges for both mechanicaland reservoir management purposes. Expensivegravel-pack completions and tubing in high-ratewells are prone to damage if there is excessivedrawdown or if the erosional velocity is toohigh.14 As flow rates were ramped up during theinitial stages of production, pressure data helpedavoid damage by ensuring that predeterminedlimits on drawdown and erosional velocity wouldnot be exceeded. By measuring the pressure dropacross the completion, engineers calculated the mechanical efficiency, or mechanical skin, of the completion.15

Acquiring a constant stream of pressure dataenables reservoir engineers to fine-tune compo-sitional models for reservoir simulation, performhistory matching of pressure depletion of thereservoirs over time, test secondary recovery scenarios and predict ultimate recovery. Thepressure data are also used for frequent pres-sure-transient analysis. This analysis providescalculations of effective permeability, mechanicalskin, non-darcy flow effects, average reservoirpressure and approximate distance to variousreservoir boundaries.

Interference tests can be performed becausethere are permanent downhole pressure gaugesin all the wells. Each well responds to rate adjust-ments in offset wells within hours. The pressureresponses can be used to assess reservoir conti-nuity. Data from pressure gauges confirmed thegeologic model of laterally continuous basin floorfan sands.

Of seven gauges installed in the Baldpatefield, six are working. The lone failure—the onlyfailed gauge out of 43 gauges installed bySchlumberger in North America—appears tohave resulted from a problem within the gaugeitself, although it has not been recovered forpostmortem analysis. The installation of gaugesin all the wells meant that the loss of one gaugewas an inconvenience rather than a major diffi-culty. It was not worth retrieving or repairing thefailed gauge because of the cost and mechanicalrisks of pulling tubing. Data from the gauges inthe other wells are sufficient for ongoing reser-voir management.

Amerada Hess carefully manages the highvolume of data from permanent downhole pres-sure gauges. The data are stored in the hard driveof a personal computer on the production tower.From the office, an engineer can control samplingrate and electronically retrieve data from theremote production tower and move them to theoffice. Eventually, however, Amerada Hessexpects to move and store the complete data vol-ume elsewhere. Data can be downloaded into apressure-transient software package and ana-lyzed within minutes.

13. For more on scale: Crabtree M, Eslinger D, Fletcher P,Miller M, Johnson A and King G: “Fighting Scale—Removal and Prevention,” Oilfield Review 11, no. 3(Autumn 1999): 30-45.

14. Erosional velocity is the velocity at which an impingingfluid degrades a metal at the molecular level. In thiscase, the operator was concerned about the possibilityof high-flow rate wells producing sand from the uncon-solidated reservoir and damaging the production tubing.

15. Pahmiyer RC, Fitzpatrick HJ, Jr. and Dugan J:“Completion Efficiency Measures for High-Permeability,Unconsolidated Sand Environments,” presented at the1999 SPE European Formation Damage Conference, The Hague, The Netherlands, May 31-June 1, 1999.

>Baldpate field location. Baldpate field is located offshore Louisiana in Block 260 of the GardenBanks area.

TEXAS

LOUISIANA

Garden Banks

Baldpate

BaldpateNorth

Enchilada

0

0 160 km

100 miles

An example from Africa demonstrates otherapplications of downhole gauges. Since 1992,Mobil Producing Nigeria Unlimited has installedpermanent downhole pressure gauges in 12 of itsfields offshore Nigeria: Usari, Oso, Mfem, Ubit,Iyak, Enang, Asasa, Ekpe, Asabo, Unam, Edopand Etim (above).16

Mobil has used continuous pressure mea-surements from downhole gauges in many ways.The most basic applications include determiningthe reservoir drive mechanism, assessing deple-tion patterns and reservoir discontinuities, andplanning pressure maintenance programs.Permanent downhole gauges measure downhole

pressure in wells whose high wellhead pressureprecludes use of wireline pressure measurementtechniques. Mobil can avoid the costs of shuttingin wells with high flow rates solely for gatheringdata. In fields with many wells, data from strate-gically placed pressure gauges allow reservoirengineers to calibrate pressure measurementsgathered by wireline methods with those frompermanent gauges.

In the Edop field, 7 of approximately 40 wellshave downhole pressure gauges. Mobil expectedto inject gas to maintain reservoir pressure, sothe initial plan was to place a downhole pressuregauge in a well in each of four fault blocks in theEdop field and assess the connectivity of the

reservoir across fault blocks. Results from thegauges showed no communication across thefault blocks, and that separate injectors would berequired for each fault block. The downhole pres-sure gauges also indicated that the plannedinjection patterns needed to be changed, so thedownhole pressure gauge data were then inte-grated with the 3D geological model to modifyand optimize producer and injector locations.

32 Oilfield Review

16. Ogunlowo RF, Ewherido UJ and Oyewole AA: “Use ofDown-hole Permanent Gauges in Reservoir Descriptionand Management of a Gas Injection Project in EdopField, Offshore, Nigeria,” prepared for the 23rd AnnualInternational Conference and Exhibition, Abuja, Nigeria,August 4-6, 1999.

17. Algeroy et al, reference 1.Huck R: “The Future Role of Downhole Process Control,”Invited Speech, Offshore Technology Conference,Houston, Texas, USA, May 3, 1999.

18. Christie A, Kishino A, Cromb J, Hensley R, Kent E,McBeath B, Stewart H, Vidal A and Koot L: “SubseaSolutions,” Oilfield Review 11, no. 4 (Winter 1999): 2–19.

Niger Delta

Qua Iboeterminal

Oil fields with downhole gauges

0 15 miles

0 24 km

AFRICA

Asabo

Enang

Edop

Asasa

Etim

UnamUbit

Iyak

Mfem

Oso

Usari

Ekpe

>Offshore Nigeria. Since 1992, Mobil Producing Nigeria Unlimited has installed permanent downholegauges in the 12 offshore fields shown in red-rimmed green. Approximately 95% of the gauges are stilloperating today.

Winter 1999/2000 33

Pressure data provided by downhole gaugeswere critical in determining communication effi-ciency around shale baffles that had escapeddetection by seismic and well logging methods.Also, the continuous data provided by the gaugesled to better reservoir simulation results than sin-gle data points from wireline measurementmethods. As the injection project proceeded,instantaneous pressure responses within thecontinuous stream of data enabled engineers todetermine how much compressor downtime theirinjection project could accommodate (right).

In other fields operated by Mobil offshoreNigeria, 20 to 25% of the wells have downholepressure gauges. Approximately 95% of thegauges provided by Schlumberger are still oper-ating. The rare instances of failure have beenattributed to problems in control lines, badcable splices, failure at the wet connector orproblems at the Christmas tree rather than prob-lems with the gauges themselves. However,these are still considered failures of the system.Improvement beyond the current 95% successrate is expected.

Outlook for Reservoir MonitoringPermanent reservoir monitoring is vital to intelli-gent completions, a modern approach to improvingreserve recovery.17 Efficient, beneficial operationof downhole flow-control valves depends onunderstanding reservoir dynamics, so the combi-nation of acquiring downhole data and usingflow-control valves is essential. At present,knowledge of the reservoir comes from analyzingpressure and production data and, in some cases,data from downhole flowmeters. Ongoingresearch and development of flowmeters areexpected to provide accurate measurement offlow rates as well as multiphase fluid properties.In addition, researchers are addressing the chal-lenges of accurately measuring flow rates indirectional and horizontal wells.

Improved links between data acquisitionsystems and operators will facilitate real-timedata transmission and display. Permanent mon-itoring allows engineers to get a sense of thereservoir, but to “see” the reservoir requiresthat the data be transformed into a usable for-mat. If data access or display is too cumbersome,downhole pressure gauge data are in danger ofbeing ignored.

The costs and economic benefits of perma-nent monitoring must be considered together.Success stories from around the world, such asthose presented in this article, should serve tobolster confidence in permanent downhole pres-sure gauges. As confidence in the dependabilityof permanent gauges and other systems contin-ues to grow, the value of the data will overcomeshort-term concerns about cost in many cases.

Today, operators are venturing into remoteareas and water depths approaching 10,000 ft[3048 m] and are completing wells subsea withthe expectation of limited or no interventions.18

Optimal production in these arenas will necessi-tate permanent monitoring systems that are compatible with other completion equipment. As with permanent downhole pressure gaugesand flow-control valves, dependability of down-hole flowmeters and other permanent equipmentin wells will remain the key criterion for choosingto deploy these devices in expensive, inaccessi-ble wells.

The successful application of rigorous prod-uct development and testing processes withconcurrent reliability engineering and field ser-vice quality control has set the standard fordependable permanent monitoring systems. Thisreflects a long-term commitment of people andresources. Employing these engineering pro-cesses enhances future permanent monitoringsystems. For operators, these enhancementstranslate into early diagnosis of problems, fewerwell interventions, reduced risk and greaterreserve recovery. —GMG

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12/98 2/99 4/99 6/99 8/99 10/99 12/99 2/00 4/00 6/00 8/00

>Pressure response in Edop field. In the central fault block, gas injection is increasingreservoir pressure, as shown in this plot of pressure measured in four different wells versus time in the Intra Qua Iboe 3 reservoir. Predicted pressures, shown in dashes, werecalculated on the basis of well placement, drainage radius, production rates and expectedgas injection rates. tmin, or April 2000, represents the earliest predicted date when thereservoir pressure will attain the target pressure (Pmax), while tmax represents the latestprojected date to reach the desired pressure and occurs in July 2000.

Twenty years ago, no one could have predictedhow much our lives would rely on data transmis-sion. Advances in communication technologyand data transfer have revolutionized the waypeople shop, access financial accounts, pursueamusements, converse, learn and interact withtheir world. Nearly every area of human activityhas been affected in some way by high-speeddata links, satellite transmission and communi-cation networks.

Technological developments in the last decadehave made data delivery faster, more secure andreliable, and increasingly convenient. The oilfieldexploration and production (E&P) industry has ben-efited from these improvements, perhaps morethan other industries, because of its global nature.Decision-makers often are at antipodal distancesfrom the assets they manage, but need updatedinformation, sometimes every hour. Ten years ago,it would have been inconceivable to believe thatdata obtained somewhere in the diverse oilfield

environment could be brought at great speed toany operator anywhere in the world. But today,data users in the petroleum industry are able tocall on an increasingly powerful array of tools,from direct communication links to private net-works and the Internet, to move crucial data any-where in the world.

This article describes how methods of datadelivery have evolved from simple point-to-pointdata transmissions to secure, multipoint Web-based systems that are easy to use. We will lookat how today’s data communication technologiesprovide efficient and secure data networking tohelp operators get the right information at theright time to evaluate their projects and makecritical, timely technical and financial decisions.Field examples are provided from each stage ofhydrocarbon production to illustrate the applica-tion and benefit of today’s evolving data commu-nication technology.

34 Oilfield Review

In-Time Data Delivery

Trevor BrownUnocal IndonesiaBalikpapan, East Kalimantan, Indonesia

Thomas BurkeAlex KletzkyAustin, Texas, USA

Ivar HaarstadStatoilTrondheim, Norway

John HensleyPhillips PetroleumBartlesville, Oklahoma, USA

Stuart MurchieHouston, Texas

Cary PurdyPOSCHouston, Texas

Anchala RamasamyBP Amoco ExplorationAberdeen, Scotland

For help in preparation of this article, thanks to Ian Alderson,James Bristow, François Daube, Moira Duff, John Kingston,Mark Osborn and Richard Woods, Gatwick, England; JorgBarsch and Ariel Skjorten, Oslo, Norway; Richard Christieand Ian Falconer, Sugar Land, Texas, USA; Alain Citerne,Jean-Noel Mauze and Leo Osugo, Clamart, France; John Driggers and Jessica Latka, Sedalia, Colorado, USA;Claude Durocher, Balikpapan, Indonesia; David Harris and Tore Moe, Stavanger, Norway; David R. Houston, IBM Global Security Services, Austin, Texas; George Karr,Yogendra Pandya and David Scheibner, Austin, Texas;Herman Kat, TransCanada International (Netherlands) B. V.,Zoetermeer, The Netherlands; and Ken Landgren and S. Omar Alam, Houston, Texas; and Fraser Louden, Dallas, Texas. AssetDB, CMR (Combinable Magnetic Resonance),DataLink, DSI (Dipole Shear Sonic Imager), Enterprise,Finder, FloWatcher, FracCADE (Fracture Design andEvaluation), FracCAT (Fracture Computer Aided Treatment),

The Internet is facilitating new on-line activities such as shopping, banking and

entertainment. Now work with E&P data can also be performed through the

Internet. Soon, operators will need only a standard personal computer or

workstation, Internet connection and a Web browser to access, review, validate

and interact with each step of data acquisition, processing and interpretation.

GeoFrame, GeoSteering, GeoWeb, IDEAL (IntegratedDrilling Evaluation and Logging), INFORM (IntegratedForward Modeling), InterACT, InterACT Web Witness,LogDB, MAXIS (Multitask Acquisition and Imaging System),MDT (Modular Formation Dynamics Tester), PDSView,PetaSTAR, Platform Express, PowerPlan, PumpWatcher,Remote Command, Remote Witness, SDMS (Seismic DataManagement System), SeisDB, SuperVISION, TransACT,TRX, and WellWatcher are marks of Schlumberger.Communicator is a mark of Netscape CommunicationsCorporation. ECLIPS and RigLink are marks of BakerHughes. INSITE (Integrated System for InformationTechnology and Engineering) and INSITE-ANYWHERE aremarks of Sperry-Sun Drilling Services. Internet Explorer,Microsoft Office and Windows are marks of MicrosoftCorporation. Lotus Notes is a mark of Lotus DevelopmentCorporation. Open Works is a mark of Landmark GraphicsCorporation. POSC is a mark of Petrotechnical OpenSoftware Corporation.

Winter 1999/2000 35

stances. Regardless of the method used, it isimportant that the data be delivered wheneverand wherever they are needed. Decision-makersalso must be given the appropriate amount ofinformation and not be swamped with irrelevantdetails. This becomes a challenge as technologyevolves and the complexity and volume ofacquired data increase.

Advances in modern data-acquisition systemscoupled with the industry’s demand for moreinformation have created additional challenges inmanaging the wide spectrum of data types andformats (see “Classifying Oilfield Data,” page 40 ).Between the data acquisition and their final useat the oil company office, intermediate data pro-cessing and analysis can help ensure that thedata quality is the highest possible, and that allthe data can be used for the intended purpose.

FinderEnterprise

System

Select

Integrate

Validate

Load

Logs

Seis

mic

Prod

uctio

n

Geo logy

W

ells

> Finder Enterprise data management system.The Finder E&P database provides on-line storageof master corporate information, such as welllog, seismic and production data. Managers, scientists and engineers use this system as asource for correct, verified and approved datathat can be viewed, selected and retrieved at anytime for analysis and interpretation. Interpreta-tion results can be saved in the master database.

Data AcquisitionThe E&P industry probably has the mostwidespread range of data-acquisition technolo-gies and domains of any commercial activity.Data come from measurements that range fromthousands of kilometers or miles at the largescale to a few angstroms at the small scale—from sedimentary basins to the wavelength oflight absorbed by hydrocarbon molecules.

E&P data come from all stages of operations,spanning exploratory seismic surveys, throughdrilling and logging, to subsurface productionmonitoring. The measurements provide informa-tion on the formation and reservoir, as well as theongoing operations, and often are used to makecritical decisions. Frequently such decisions needto be made as soon as data are acquired, eitherat the acquisition site, or more often at a centraloffice or base location where all the requiredexperts are available. Reliable data communica-tion technology allows such collaboration tooccur with ease, thus facilitating more knowl-edgeable and better decisions. If the decisionwindow is small or immediate, then the operatormay need to transmit data in real time from theacquisition site and interact remotely with theacquisition process simultaneously.

For any given project, the service providers,decision-makers and partners are unlikely to belocated in the same place. Through multipoint,two-way communication, today’s technologyfacilitates “virtual” collaboration in such circum-

For operators who do not wish to perform post-acquisition data processing, analysis and interpre-tation in-house, service companies can providethese services in their data processing centers.

Data processing centers—At these centers,expert personnel with advanced software pack-ages extract the essential information from theraw data files and interpret the results, present-ing them in a meaningful format for decision-makers. Efficient data delivery is essential to theirwork. These data processing centers may belocated in the offices of the operator or a serviceprovider. Personnel at typical processing centersinclude log analysts and interpretation expertsqualified in the geosciences. The range of soft-ware applications available to them is extensive,encompassing borehole seismic data processing,geological analysis, borehole imaging, petro-physics, well testing, production engineering,signal-processing and interpretation functionality.

Data management centers—In the past, theintegration of data from the different domains(seismic, drilling, production, reservoir engineer-ing), either recently acquired or pulled from anarchive, has been a difficult and inefficient man-ual task. The Finder Enterprise system, developedby Schlumberger to provide all the elements ofan integrated data management and archive sys-tem, embraces every domain of the E&P industry(above). This system provides best-practice pro-cedures and one-stop shopping for all types of

required data. The ability to combine and corre-late reliable data among multiple wells anddomains further enhances the value of all thedata.1 Furthermore, an efficient data-management,archiving and retrieval system can help inter-preters exploit knowledge from data previouslyacquired and benefit from the experience gainedduring acquisition.

The Finder Enterprise data-management archi-tecture has been designed around the principaldata-management and data-access functions:loading, validation, editing and integration. Thesefunctions enable users to find, access and transferany oilfield data. The architecture comprises adata catalog covering individual master databasesand systems designed to register and synchronize

corporate repositories and master databases intoa well-organized environment. A description ofsome of its major components follows: • the Finder system—a comprehensive data

store for geology, and geophysics, productionand drilling data

• the LogDB archive—a comprehensive well-logarchival system

• the SeisDB archive—a seismic data-manage-ment system for archiving, viewing and restor-ing bulk seismic data

• the SDMS/PetaSTAR system—a seismic data-management solution for workstation-basedseismic data

• the AssetDB system—a record inventory man-agement system that allows oil companies tostore, organize and track a wide variety ofphysical E&P data assets.

As part of the Finder data-management sys-tem, the GeoWeb 3D viewing software enables adata user to view, verify, select and retrieve E&Pdata from a single point of entry (left). Using aWeb browser, data users can view and literally“dig” down into their LogDB original-format logarchive, their SeisDB seismic trace archivaldatabase and their AssetDB physical data man-agement system by launching applications withinthe Finder data-management system.

Data Delivery Technology During the last thirty years, there has been a con-tinual development of communication solutionsused to transmit oilfield data from the acquisitionsite to end users. These solutions have rangedfrom commercially available systems, such as thebasic programs using file transfer protocol (FTP),to custom solutions built by operators and ser-vice providers (see “Glossary,” next page). Eachmethod has evolved from previous ones, drivenby additional industry requirements and sus-tained by developments in communications tech-nology. Today, the common feature of all thesetechnologies is that they are based on the TCP/IPprotocol (see “TCP/IP Data Protocol,” page 44 ).

In general, today’s data transmission solu-tions can be grouped into three general modes inchronological order of their development: • point-to-point—only one sender and one receiver

regardless of the connection being utilized• multipoint data delivery using a private network• Internet-based multipoint data delivery.

36 Oilfield Review

Select requireddata

Select datarepository

Visualize andanalyze data

Launchdrill-downmodules

Well-based,third-party

applications

Geoscientist

AssetDB SeisDB

Databases

LogDB

Informationshopping bag

GeoWeb workflow. As part of an integrateddata management system, GeoWeb softwarecan be used to select, retrieve, view and verify E&P data on a local computer or work-station—providing a virtual information shopping bag to collect data for processing.For example, data can be loaded directly intoa GeoFrame system software application for advanced formation, petrophysics and reservoir analysis.

1. Beham R, Brown A, Mottershead C, Whitgift J, Cross J,Desroches L, Espeland J, Greenberg M, Haines P,Landgren K, Layrisse I, Lugo J, Moreán O, Ochoa E,O’Neill D and Sledz J: “Changing the Shape of E&P Data Management,” Oilfield Review 9, no. 2 (Summer 1997): 21-33.

(continued on page 38)

>

authentication—The process of identifyingusers, typically by user identification (user-id)and passwords, before they are allowed accessto computer systems or networks, typically byuser-id and passwords.

browser—A software program that runs on theuser’s computer, allowing connections to Webpages and services.

datagram—A message unit that contains sourceand destination address information, as wellas data, which is routed through a packet-switching network. Also referred to as apacket, frame or block.

digital certificates—An encrypted digital signa-ture used for authentication to prove the iden-tity of an individual, a provider of a service, aproduct vendor or a corporation. Digital cer-tificates are issued by a trusted organizationthat validates and issues certificates, oftencalled a “trusted authority.”

DropBox—A secure computer file locationbetween protected company intranets. It serves as a data exchange location.

e-business—Financial transactions performedthrough the Internet without paper, synony-mous with e-commerce.

encryption—The process of scrambling informa-tion so that a key held only by authorizedrecipients is needed to unscramble and readthe information again.

Ethernet—A popular networking system with a high transfer rate and several cabling schemes.

extranet—A technology that allows differentcorporate intranets to communicate for thepurpose of electronic commerce and collabo-ration. Those parts of an extranet outside the firewall contain their own set of securitysafeguards, allowing only limited access forspecific purposes.

firewall—A barrier established in hardware orin software, or sometimes both, that monitorsand controls the flow of traffic between twonetworks, usually between a private local area network (LAN) and the Internet.

freeware—Software made available at no costfor public use by the author. The PDSViewsoftware for displaying and annotating loggraphics on a PC is freeware fromSchlumberger.

FTP (File Transfer Protocol)—The TCP/IP protocol used when transferring single or multiple files from one computer to another.FTP provides all the tools needed to look at

directories and files, change to other directo-ries and transfer text and binary files from onecomputer system to another.

HTML (Hypertext Markup Language)—A standard document-formatting languageused for creating Web pages and other hypertext documents.

HTTP (Hypertext Transfer Protocol)—Thecommand and control protocol used to managecommunications between a Web browser and a Web server.

HTTPS (Secure HTTP)—An extension to the Hypertext Transfer Protocol (HTTP) from Enterprise Integration Technology that allows Web browsers and servers to sign,authenticate, and encrypt a HTTP packet at the application layer.

Inmarsat—International Mobile SatelliteOrganization, an international cooperativethat provides worldwide communications tomarine, land and airborne operations througha network of geosynchronous satellites andland-based stations. Currently, more than 160countries use the Inmarsat satellite system.

Internet—The world’s largest computer net-work, consisting of millions of computers sup-porting tens of millions of users in hundreds of countries. The Internet is growing at such a phenomenal rate that any size estimate isquickly out of date.

intranet—A private corporate network that usesInternet software and TCP/IP networking pro-tocol standards. SINet and SOIL are examplesof intranets.

IP (Internet Protocol)— The set of specificationsthat regulate information packet forwardingby tracking addresses, routing outgoing mes-sages, and recognizing incoming messages in TCP/IP networks and the Internet.

ISDN (Integrated Services Digital Network)—The current system for digital transmission,allowing rates of 64 kilobits per second (Kbps)per line.

packet—A unit of data—containing addressinformation, data and error-checking informa-tion—sent over a network or communicationslink. Also referred to as a datagram, frame or block.

PKI (Public Key Infrastructure)—An encryptionscheme that uses two keys. In a data transac-tion, a public key, given to the sender, encryptsthe data before transmission. Upon receipt, thereceiver uses a corresponding private key todecrypt the transmission. Because the private

key is never transmitted or publicized, theencryption scheme is secure.

routing—The process of locating the mostefficient or effective pathway through a net-work to a destination computer. The networkor communications software commonlyhandles routing.

smart card—An identification and security card the size of a credit card, but with anembedded microprocessor that can store thedigital certificate and other relevant informa-tion such as frequently used passwords.

TCP/IP (Transmission Control Protocol/Internet Protocol)—A set of communicationprotocols used on the Internet (see “TCP/IPData Protocol,” page 44).

VPN (Virtual Private Network)—Originally a private network for voice and data based on security technology for transmission onpublic lines and connections. More recently,VPN is an encrypted private tunnel across the Internet.

VSAT (Very Small Aperture Terminal)—A small satellite terminal used for digitalcommunications, from 1 to 3 meters (3.3 to 10 ft) in diameter. The VSAT is used bySchlumberger locations primarily in NorthAmerica for high-speed, up to 128 Kbps, communications from logging units to geosynchronous satellites.

Web browser—An application, such asNetscape Communicator or Internet Explorer,that permits users to look at hypertext docu-ments, follow links to other HTML documents,and download files to their computers fromthe Internet.

Web server—A hardware and software packagethat provides services to users’ computers running Web browsers.

WITS (Wellsite Information TransferSpecification)—An industry standard (API)protocol used to send and exchange informa-tion about ongoing wellsite operations.

WWW (World Wide Web)—One of the majorareas of the Internet. It is a hypertext-basedsystem for finding and accessing Intranetresources. Physicists at the EuropeanLaboratory for Particle Physics in Switzerlanddeveloped the original WWW concepts forexchanging scientific information.

XML (Extensible Markup Language)—A technology that allows the data on an HTML page to be described in terms of theinformation it represents.

Glossary

Winter 1999/2000 37

38 Oilfield Review

Security is a concern requiring custom solu-tions. Recently developed security firewalls anddigital authentication technologies allow opera-tors to collaborate with one another and withservice providers through private networks(below). The Schlumberger Connectivity Center(SCC) resolves many of the important networkrouting and security issues that arise when con-necting to external networks, both private andpublic. Web- and FTP-based data delivery and theSchlumberger Data Management Center areaccessible through the SCC.

Point-to-Point Data Delivery Point-to-point data delivery has been used inwell logging since the early 1960s and stillserves as a major data communication mode inthe oil field. Data are sent directly from theacquisition site through a communications link tothe data user’s or operator’s office (right).

The advantage of point-to-point data deliveryis that the data are “pushed” all the way to theirdestination without any intervention from thereceiving end. In addition, this technology isindependent of any other data delivery or com-

munication system. With recent systems, thesame data link is used for two-way communica-tions, allowing the operator in the office to be notjust a passive recipient of the data but an activeparticipant in an interactive acquisition process.

The easy-to-use InterACT Remote Witnesssoftware, designed for wireline logging, is aninteractive data delivery package that is used forpoint-to-point data communications. It utilizesrobust and efficient compression algorithms tomove large amounts of data in real time from theacquisition site to the client’s desktop. Digitalgraphics are displayed automatically in real time

Firewall Firewall

Operator 1

Operator 2

Operator 3

Operator 4

Operator 5

Operator 6

Extranet applications

SchlumbergerConnectivity Center

Helpdesk

> Schlumberger Connectivity Center (SCC). The hardware and software for the (SCC) were created toconnect operators and their partners to Schlumberger network-based information and data deliverysystems. The SCC provides authorized secure access to a variety of Schlumberger services through asingle, centrally managed connection. To ensure the security of all the resources within the Schlum-berger Information Network (SINet), all extranet applications are located in a secure enclave. Thesesecure enclaves are logically outside SINet, and therefore assigned IP addresses outside the SINetaddress range. The secure enclaves can be connected back to the SCC either through a dedicatedcommunication connection, such as a leased line, or through an encrypted connection through SINet.Web and FTP-based data delivery and the Data Management Center are examples of servicesaccessible through the SCC.

An

adri

ll

Schlumberger

Data services center

Operator desktopData acquisition site

> Point-to-point data communications. Thistransmission option pushes data from the acquisition site to the destination site such as an operator’s desktop computer (top) or the dataservices center (bottom). The communicationslink can be provided by a number of differentcommunications options, such as a direct phoneline, satellite link, or a dedicated ISDN line to the destination site.

and scrolled on-screen using the PDSView soft-ware (right). Graphics can be annotated, con-verted to commonly used graphics interchangeformat (GIF) and computer graphics metafile(CGM) formats or printed on a commercial plotteras they arrive.

The InterACT Remote Witness system alsoprovides powerful two-way communications utili-ties with the wellsite crew using the data chan-nel. Such utilities include “chat” applications thatpermit rig personnel to exchange audio messagesthrough computers equipped with a sound card,speakers and microphones. In addition, this sys-tem provides videoconferencing facilities that areused to connect service vessels, offshore rigs andremote land locations to the client’s desktop orlaptop computer. The InterACT Remote Witnessservice is one of the most widely used point-to-point data delivery systems in the industry.

BP Amoco initiated a program of remote wit-nessing during well logging acquisition on theirwells in the Andrews field in the North Sea usingthe InterACT Remote Witness communicationssystem.2 The InterACT system provided direct andimmediate interaction between the offshorewellsite data-acquisition team and the consul-tants in the Aberdeen and London offices duringlog acquisition for improved decision-making.

In describing the system’s value, a petro-physicist from BP Amoco Exploration, who workson high-value wells in the North Sea, reportsthat the use of the InterACT system on the BPAmoco Andrew platform fulfilled a number ofrequirements—not the least, from a safety per-spective—through removing the need for off-shore witnessing. In addition, it provided reliefin a restricted personnel environment. BP Amocofound it beneficial during production logging forthe reservoir engineer and petrophysicist to beable to discuss and influence the real-time log-ging program—such as reactions to unforeseenchanges in environment and the ability to makedecisions from onshore if required. By the sametoken, during pipe-conveyed logging, the loca-tion of formation tester sampling points could beconfirmed and the usual pressure responseschecked with modeled results, preventing anycostly reruns.

Real-time communication with the engineerthrough the InterACT chat tool is valuable duringprejob checks and rig-up to relay information ontool performance quickly. During one of the earlyruns of the Borehole Acoustic Reflection Survey(BARS) tool, the onshore tool expert and petro-physicist along with the data processor used thechat tool to check imaging quality and alterparameters during logging. Then they processedthe InterACT-transmitted data in-house providingthe answer product within 24 hours.

Unocal Indonesia pioneered using theInterACT Remote Witness system to help assestheir West Seno deepwater exploration andappraisal wells. Using the MDT ModularFormation Dynamics Tester tool pressure gradi-ents to look for matching sands, the operatorswere able to correlate zonal communicationbetween wells. The real-time data enabled oper-ators to guide the team at the acquisition site totake measurements where needed to help inter-pret the evolving picture of reservoir connectivity.The real-time data and interactive communica-tions allowed Unocal to successfully completethe difficult process of reserve certification.

Another major operator used the InterACTRemote Witness system to evaluate log qualitycontrol during a deepwater wireline logging opera-tion in Nigeria. During acquisition, the field engi-neer transmitted the logging data directly to theSchlumberger Center for Advanced FormationEvaluation (SCAFE) in Houston, Texas, by telephonefrom the rig in Nigeria. Both log analysts and tech-nical advisors from the operator and Schlumbergerwere present as logs arrived from the wellsite andwere displayed and printed in real time. Data fromthe CMR Combinable Magnetic Resonance toolenabled the operator’s log analyst to locate addi-tional zones containing hydrocarbons. The two-way communications channel provided by theInterACT Remote Witness system enabled the ana-lyst to advise logging engineers when enoughhigh-quality critical data had been acquired, mini-mizing the rig time needed for data acquisition. Italso saved a costly trip to Nigeria for the operator’sexperts and allowed them to continue their regularwork with a minimum of disruption.

> PDSView graphics software. This freeware application allows users to display and annotatewell log graphics on a PC. Its popularity in the E&P industry is a tribute to the great value ofthe digital graphics. Windows elements, such as the toolbar (top ), allow for a wide range of graphic annotations that include text inserts, callout boxes, re-editing and saving of theedited files.

Winter 1999/2000 39

2. Barber T, Jammes L, Smits JW, Klopf W, Ramasamy A,Reynolds L, Sibbit A and Terry R: “Real-Time OpenholeEvaluation,”Oilfield Review 11, no. 2 (Summer 1999): 36-57.

(continued on page 42)

The format and quality of E&P data havebecome as important as their acquisition andtransmission. The time and effort spent on dataacquisition and data delivery will be wastedunless the delivered data can be readily utilized.Data are truly delivered only after they havebeen integrated and stored where the operatorcan get them. Complex data previously pre-sented on paper are easily delivered in digitalformat. However, the increasing complexity ofdigital data has necessitated categorization anddocumentation of data types to ensure smoothdelivery and accessibility by operators. Severaldefault classifications have been implemented:• Basic data—This group contains data, usually

presented optically, used without modifica-tions by a broad spectrum of professionals.Basic data are limited in size and are suitablefor timely exchange and quick exploitation.

• Customer data—In this category are basicdata plus the essential minimum supplemen-tal information that support them. Customerdata are suitable for data storage andadvanced exploitation by specialists.

• Producer data—These data contain, in addi-tion to basic and customer data, other informa-tion meaningful to the producer of the data.Technical objects (such as tools, equipment,

processes, channels and parameters) are identi-fied by dictionary-controlled names. Registeringproper names and properties for objects is aprerequisite to an efficient data delivery system.Schlumberger maintains a public version of itsOilfield Services Data Dictionary (OSDD) on theWeb (http://www.connect.slb.com).

Data FormatsThe format of digital data can be broadly classi-fied into two categories: American StandardCode for Information Exchange (ASCII) andBinary. ASCII formats are generally simple, butcan be read by a wide range of software. Binaryformats generally have richer descriptions ofthe data, and are more appropriate foradvanced processing and long-term storage.

Graphical formats—A visual representationof digital data, graphical data are used to effi-ciently display large volumes of data in formsthat can be readily understood for simple inter-pretation or quality-control purposes. However,graphical data cannot be reused easily.Graphical data may be in hard copy (paper orfilm) or digital file format, but are essentially a“snapshot” of the data. Graphical data are gen-erated by applying a format description, presen-tation description or style sheet to the digitaldata; the resulting data may be in one of manycommercial or proprietary graphics formats.

Examples of graphical data file formats aregraphics interchange format (GIF), Joint Pho-tographic Expert Group (JPEG), tagged imagefile format (TIFF) and Picture DescriptionStandard (PDS). The two general types ofgraphical data formats are raster and vector.Raster files are composed of colored pixels thatcombine to produce a representation of thedata. Raster files cannot include objects such as lines or curves. However, raster files are gen-erally easy to view with a wide range of Internetbrowsers, word processors or other commer-cially available software. Vector files containobjects such as lines and curves with an associ-ated descriptive language. Although more effi-cient than raster files, vector files usuallyrequire viewer software specifically written foreach vector format. Both raster and vector filesmay be rendered into hard-copy prints or film.

Log ASCII standard—Originally released in 1989, The Canadian Well Logging Society’s(CWLS) Floppy Disk Committee designed astandard ASCII format for single-well log dataon floppy disks, known as the LAS format (LogASCII Standard). LAS consists of individual datafiles written in ASCII. It represents the well logheader and optical curve in digital form.Renowned for its ‘just-right’ mix of size, porta-bility, ease of use and accessibility, LAS has nowbecome an accepted method of rapid well logdelivery for E&P companies worldwide. Its sim-ple structure, with familiar spreadsheet-likecolumns of log data indexed to depth, makes iteasy to use or load into most application soft-ware. Its ASCII file structure assures that allcomputer operating systems can open and readLAS files. Most appreciated is the user’s abilityto simply open the file in any text editor andextract well information visually.

Log Information Standard—The LogInformation Standard (LIS) binary data formatwas produced on Schlumberger acquisition systems during the 1970s and 1980s. It was thewireline logging industry standard data formatuntil it was superceded by the Digital LogInterchange Standard (DLIS) in the 1990s.

Recommended Practice 66/Digital LogInterchange Standard—The RP66/DLIS stan-dard became an American Petroleum Institute(API) Recommended Practice (RP66) in 1991.The Petrotechnical Open Software Corporation(POSC) adopted the DLIS standard in 1992,triggering its development as a syntactic stan-dard for seismic, drilling and well logging. The DLIS standard proposes a data scheme thatpermits the storage, management and exchangeof quality data. By specifying equipment, tool,process and data, the format ensures the trace-ability required by the E&P industry.

Classifying Oilfield Data

1. Morgan JG, Spradley LH, Worthington GA andMcClelland IJ: “SEG Standard Exchange Formats forPositional Data,” Geophysics 54 (January 1983): 102-124.

2. More information about Practical Well Log Standardsand WellLogML can be found at the POSC Web site(http://www.posc.org).

40 Oilfield Review

Winter 1999/2000 41

It supports a way to classify data and conse-quently provides ease of data access. The DLISstandard also effectively conveys the data pro-ducer’s semantics for tool, equipment, process,channel and parameters through officialdescriptions stored in the specific data record.

The features and advantages of DLIS and LIS can be compared:• LIS allows only four-character names. DLIS

allows longer ones.• Every DLIS object has an origination identifier

telling who created the data and when, whereand how they were created.

• DLIS static data give much more informationabout the data acquisition environment andcalibrations than LIS data. The DLIS staticdata are self-describing and can be extendedwith new object types.

• DLIS can record data with complex struc-ture, such as packed waveforms and images.LIS cannot.

• DLIS can record data frames with differentsampling rates in one file. LIS can only recordframe rates that are multiples of the baseframe rate.

In comparing DLIS with Log ASCII Standard(LAS), some features and advantages of DLISand LAS are evident:• LAS has only static data about the well and its

associated parameters. Unlike DLIS, it con-tains no information about tools, equipment,calibrations or other attributes.

• LAS stores numbers as ASCII values andrequires about three times more storagespace than DLIS.

• LAS files can be opened with a spreadsheet or text editor. DLIS files require special software libraries. WITS (Wellsite Information Transfer

Specification) WITS was designed as a jointindustry effort sponsored by the InternationalAssociation of Drilling Contractors (IADC) andis the generally accepted protocol for sharingdata among various contractors on a rig.Standard records provide data on rig conditions,directional surveys, cementing, basic formation

evaluation and other common rig activities. In addition, there is provision for custom recordsthat allow proprietary data to be exchanged aslong as the data in the records have beenagreed on by the sender and the receiver. WITSis a suitable format for drilling data transmis-sion due to its ability to transfer depth-stampeddata efficiently and in real time.

SEG-Y—Currently, seismic field data arerecorded in a number of the Society of Explora-tion Geophysicists (SEG) formats.1 SEG-Yprovides a convenient, simple method for inter-changing data sets, as virtually all computersystems in the seismic industry have softwarecapable of reading this format.

WellLogML—A Future ASCII Data Format for the E&P Industry?The use of the Internet to exchange electronicbusiness (e-business) documents and technicaldata is growing rapidly. Organizations engagedin e-commerce are quickly converging on theuse of the extensible markup language (XML) asthe best way to exchange information. The XMLstandard—defined by the World Wide WebConsortium (W3C)—is a simple, easy-to-graspmethod of encoding information in plain text.Because of XML’s simplicity and broad industryappeal, a wide spectrum of tools is rapidly beingdeveloped to support its user community.Support for XML is even included in populardesktop tools like Microsoft Internet Explorer5.0 and Microsoft Office 2000.

Work has already begun on defining an XMLstandard for the E&P industry, called WellLogML.With WellLogML, borehole information such as well logs, coring information, and waveformand other data can be transmitted via theInternet and then displayed using a Web browser.WellLogML can be easily incorporated intoexisting log analysis software because there are several free XML parsers, editors and otherutilities available from companies such asMicrosoft and IBM. WellLogML is also an ASCIIformat, making it readily understandable.

Practical Well Log Standards—A New Industry InitiativePractical Well Log Standards is a current indus-try collaborative project, including Shell Inter-national Exploration and Production, Statoil,Norsk Agip, Norsk Conoco and Schlumberger,formed to establish standards for the creation of a clearly labeled well-log data set that isaccessible to a wide range of E&P professionals.2

The project leverages the work done on previousprojects, including OSDD and development ofPOSC standards. Expected benefits resultingfrom this project include the following: • reduced costs through process improvement• better data identification and characterization• improved data access• improved data loading efficiency• faster data preparation and acceptance for

data exchange or sale• increased accessibility and understanding

of logging data by nonpetrophysicists.Data consumers are overwhelmed by the

amount of data they receive. Currently thereare more than 50,000 different types of well-logtraces. However, most will agree that the num-ber of routinely used well-log traces is some-where in the neighborhood of 500. Additionally,the names of traces are complex and are chang-ing at an ever-increasing rate. These factorspresent several problems for data loading andacquisition, such as how to classify ‘useful’ dataand how to track the level of data processing.

The results of this confusion are lost data, lostinformation and lost revenue. It is not uncom-mon for purchased data to be—in effect—thrown away, because it would cost more tounderstand the data than it would to reacquirethe data. Field studies are repeated in theirentirety at significant cost, either because datafrom previous studies can’t be identified, or because data from the studies can’t be adequately understood, and because of a lack of confidence in the results, primarily due aninability to understand the archived resultsfrom the previous studies.

42 Oilfield Review

Similarly, Phillips Petroleum used the InterACTRemote Witness system at their offices inBartlesville, Oklahoma, USA, to follow theprogress of a logging operation in the Bohai Bay,offshore China. Platform Express and DSI DipoleShear Sonic Imager data were transmitted in realtime from the acquisition site using a wellsitesatellite link. The availability of the logging data inBartlesville allowed the operator’s expert to imme-diately see and interpret the resistivity and poros-ity logs to identify potential pay zones. These wereused to find the best pressure test and samplingpoints for a subsequent MDT tool run. The chatapplication of the InterACT Remote Witness soft-ware helped the operator communicate with thelogging engineer at the acquisition site.

Another example of a point-to-point data com-munication system is the InterACT RemoteCommand system designed for logging-while-drilling (LWD) and measurements-while-drilling(MWD) data acquisition. It is widely used in manydirectional-drilling operations because it providesremote real-time monitoring through the installa-tion of a duplicate Anadrill wellsite data-acquisi-tion system in an operator’s office. This systemreplicates the capabilities of the wellsite systemand allows the display and printing of both real-time and memory logs, including real-timeGeoSteering monitoring, correlation and analysisof directional data versus the well’s plannedtrajectory. Progress also can be checked againstinformation from offset wells. The InterACTRemote Command system utilizes the WellsiteInformation Transfer Specification (WITS), andprovides powerful communications utilities, suchas e-mail, chat and audio messaging, for two-waycommunication with the acquisition site.

Norsk Hydro’s Petroleum Technology Group inBergen, Norway used InterACT RemoteCommand data exchange to steer wells beingdrilled through the highly faulted formations ofNjord field in the North Sea. The meanderingwellbores are very difficult to navigate and real-time LWD and MWD data on the GeoSteeringscreen help track the bit and keep it within thereservoir. Typically, the operator drills throughfault blocks in the reservoir section and usesreal-time LWD data to determine if the wellboreis still in the reservoir, or above or below it afterentering a new block. The real-time data alsohelp pick the total depth of the well.

The LWD data are acquired on the Njord plat-form using the IDEAL Integrated DrillingEvaluation and Logging acquisition system, andthe data are transferred to a remote IDEAL acqui-sition system in the drilling office in Kristiansund,Norway. Here the engineer generates real-timelogs and numeric displays of LWD data alongwith the drilling mechanics data (left). Theresults are sent using a TCP/IP point-to-pointconnection over Norsk Hydro’s intranet directly tothe operations geologist’s personal computer (PC)in Bergen. This PC can also be used to archive thereal-time and memory logs from the LWD toolsuite. Digital graphics are sent from the rig to thegeologist’s PC and high-quality prints are made inthe office for daily meetings. These log graphicsare e-mailed to partners outside the network andcan be viewed using PDSView software.

Real-time drilling decisions require closecooperation and good data communicationsbetween the service team and the operator assetteam. In the southern North Sea, British Gas hascombined point-to-point LWD data delivery withforward modeling and interpretation to helpmake well-steering decisions. Accurate visual-ization of the formation character and structurerelative to the drill bit improves intricate drillingnavigation in horizontal wells. The INFORMIntegrated Forward Modeling program producessynthetic LWD logs that can be compared withactual tool readings to generate a map of the for-mation as it is being drilled.3

First, LWD data acquired at the rig site aretransmitted in real time to the data processingcenter, where a GeoSteering analyst using anIDEAL PC networked to a GeoFrame workstationupdates the forward models in real time basedon the acquired data (next page). The combined

Operator desktop

> Data delivery and GeoSteering services. Access to all the real-time measurements fromlogging tools (top), numeric displays (bottom right ), and toolface displays (bottom left )help the geologist evaluate the drilling program and position of the wellbore. The loggingdisplay shows real-time LWD data plotted against depth including gamma ray (green) intrack 1, phase-shift resistivity (red) and attenuation resistivity (green) in track 2, and for-mation density (red) and porosity (green) shown in track 3. Drilling mechanics data includerate of penetration (red) shown in track 1, and MWD turbine speed for washout detection(green) in track 4. The numeric display can show the actual numerical value (boxes) or asimple bar graph (upper right) of any time-based measurement, such as pump pressure,downhole weight-on-bit, bit inclination and azimuth, rate of penetration, downhole annu-lar pressure and equivalent circulating density. Alarms can be set on any measurement (red boxes). The directional driller uses the toolface display to see how well steering is proceeding. The Gravity Tool Face (GTF) display shows the orientation of the motorbend housing based on the MWD accelerometer readings. The GTF readings around 0°inclination mean the motor and bit are being steered upwards.

3. Allen D, Dennis B, Edwards J, Franklin S, Livingston J,Kirkwood A, White J, Lehtonen L, Lyon B, Prilliman J and Simms G: “Modeling Logs for Horizontal WellPlanning and Evaluation,”Oilfield Review 7, no. 4 (Winter 1995): 47-63.

system allows correlation of the actual LWDlogs with the forward-modeled logs, confirmingwellbore location. It also estimates formationdip and produces an updated structural model of the drilled sequence as the well progresses.

Finally, the driller or operator compares thisinformation with the geological and drilling con-straints to guide navigation. The latest real-timeresults of the GeoSteering screen correlation,image and petrophysical interpretations are dis-tributed in time for daily operations meetings.The operator also maintains a Web site, onwhich all results are posted immediately,enabling other offshore and onshore projectpersonnel to access the results.

In one well, the relative thinness of the reser-voir, lack of petrophysical contrast in the bedsand uncertainty in seismic depth conversion cre-ated a risk of drilling out of the reservoir. TheGeoFrame workstation was used to process the

azimuthal density memory data obtainedbetween bit runs (previous page, insert). Thishelped determine the formation dip, which wasused to update the map of the structural modelson the GeoSteering screen. These provided theanalyst with an unequivocal interpretation of therelative position of the wellbore in the formation.The decision was made to steer down to pene-trate the lower portion of the reservoir.

Point-to-point data communication also isbeing used for monitoring well stimulations and fracturing treatments. The SchlumbergerFracCAT fracturing computer-aided treatmentdata-acquisition system provides stimulationdata—pump rates, pressure and proppant con-centration—at the wellsite. However, thesemeasurements can be extended to remote loca-tions using a real-time data transmission (RDT)system. This system allows direct communica-tions between the wellsite data-acquisition

system and a remote FracCAT system located inan operator’s office or regional technology cen-ter. Here stimulation experts can monitor thetreatment parameters in real time, evaluatetreatment progress and participate in decisionsabout treatment design and execution.

A complete FracCAT system was installed ina Houston office, where operators such asCoastal Oil and Gas and Vastar Resources rou-tinely monitor treatments performed offshore inthe Gulf of Mexico. The RDT service allows oper-ator representatives to monitor and support thewellsite operations without requiring travel tothe wellsite, eliminating unproductive travel andwaiting time. For example, completion engineerscan monitor the evolution of a fracture treatmentusing the FracCADE fracturing design and evalu-ation software and advise the crew to adjust the pump rates and proppant concentrations foroptimum results.

Winter 1999/2000 43

Data acquisition INFORM screen

IDEAL

MWD/LWDsensors

Data services center

GeoSteeringscreen

GeoFrame workstation

> GeoSteering maps with forward models. Forward modeling produces synthetic LWD logs along the planned well trajectory that are compared with actual real-time LWD logs (upper right ) to help guide the drilling process.Pilot well or adjacent well data are used to build up one or more geologic columns to represent the expectedgeology of the well. The 3D structural model obtained from the operator is also combined with the petrophysicalcolumn and proposed well trajectory. Tool responses are predicted based on the expected layered formationsequence, wellbore inclinations, bed thickness and sensor measurement resolution. The insert (white box) showsthe azimuthal density image, processed on a GeoFrame workstation, used to determine formation dip.

(continued on page 46)

Transmission Control Protocol (TCP) andInternet protocol (IP), generally mentionedtogether as TCP/IP, are protocols speciallydeveloped to allow cooperating computers toshare resources across a network. Since identi-cal functions are needed by many networkapplications, separate protocols have beengrouped together rather than being replicatedin each application. A “layering” strategyerected on several tiers of protocols is used innetworking technology. Each of these layerscalls on the services of the one below it (below).In this article, we consider the network suite ofprotocols to be divided into four basic layers.1

• Application protocol is the set of rules thatgovern software programs or services that usethe network, such as e-mail, Internet access ordata delivery packages. Both the commerciallyavailable FTP and the Schlumberger propri-etary TRX transmission software for digitaldata transfer are examples of services at theapplication protocol level. They both useTCP/IP to perform file transfers.

• Transmission Control Protocol (TCP) isresponsible for breaking up the informationinto small pieces and reassembling the infor-mation back in the right order at the otherend. It also takes care of re-sending any pieceof information that for some reason may havefailed to make it to the receiving end.

• Internet Protocol (IP) is responsible for rout-ing the individual pieces of information totheir correct destination. IP is not involvedwith the contents of the information or how agiven piece of information relates to any otherone before or after it.

• Medium protocol is the standard for thephysical connection, which involves differenttypes of links such as Ethernet, SmallComputer System Interface (SCSI) andmodems among others.TCP and IP are built on “connectionless”

technology concepts so that direct connectionsbetween the sender and receiver are notrequired. TCP breaks down the information intosmall pieces called datagrams or packets. Eachof these datagrams is numbered sequentiallyand is passed on to IP to be sent individually tothe other end through the network. While thosedatagrams are in transit, the network doesn’tknow if there is any relationship between them.

For example, it is perfectly possible that data-gram 7 will actually arrive before datagram 6. Inorder to make sure a datagram has arrived at itsdestination, the recipient has to send back an“acknowledgement.” For example, sending adatagram with an acknowledgement of 1800indicates that the specific computer hasreceived all the data up to datagram number1800. If the sender doesn’t receive an acknowl-edgement within a reasonable amount of time,then TCP sends the missing datagrams again.

TCP/IP Data Protocol

Application protocol

TCP protocol

IP protocol

Medium protocol

E-mail, Internet access, data delivery software

Ensures that commands reach the destination protocol completely and as ordered

Provides the basic service of getting datato their destination

Manages the specific physical connection mode

Actual link

> Layered scheme of network protocols.

44 Oilfield Review

1. The details of the full International Organization forStandardization (ISO) reference model can be found inmost data communications textbooks, such as Halsall F:Data Communications, Computer Networks and Open Systems, 4th ed. Harlow, Essex, England: Addison-Wesley, 1998.

2. The term catenet, introduced in early publications on packet network interconnections, refers to the interconnected collection of packet networks.

PC #1

PC #2

PC #3

PC #4

PC #5

GatewayPC #1

PC #2

PC #3

PC #4

Gateway

Gateway

PC #2 PC #3PC #1

PC #5 PC #6PC #4

LAN A LAN B

LAN C

Gateway

To othernetworks

>Wide area network (WAN) constructed from three local area networks (LAN).Gateways or firewalls provide security between each component of the network.

10100011 10111001

Network ID Host ID

11111010 00010100

> A typical IP address with the network and hostidentification parts.

Winter 1999/2000 45

TCP controls the volume of data that is intransit at any one time. It is not practical towait for each datagram to be acknowledgedbefore sending the next one. On the other hand,a computer can’t just keep sending data or afast computer might overrun the capacity of aslow one to absorb data. Thus, each end indi-cates how much new data it is currently pre-pared to absorb through a “window” field ineach acknowledgement. As the computerreceives data, the amount of space left in itswindow decreases. When it goes to zero, thesender stops. As the receiver processes thedata, it increases its window, indicating that it is ready to accept more data.

TCP/IP is based on the “catenet” model, whichassumes that there is a large number of indepen-dent small networks connected together by gate-ways or routers (right).2 Datagrams will oftenpass through many different routers before arriv-ing at their final destination. In most cases,these networks are set up in such a way that allmachines physically located in certain buildingsor departments comprise what is called a localarea network (LAN), and then several LANs arelinked together through the catenet model toform a wide area network (WAN).

The routing needed to accomplish this is completely transparent. As far as the user isconcerned, the only thing needed to accessanother system is its “Internet address.” Thisaddress is a 32-bit number, usually written asfour numbers separated by decimal points, thatthe system administrator assigns to each com-puter in the network (right). The structure ofthis address indicates both the network and thehost computer within the network. The part thatindicates the network is called “Network ID”and the part that identifies the computerwithin that network is called “Host ID.”

46 Oilfield Review

Other data-acquisition providers in the oil andgas industry have implemented specialized point-to-point data delivery systems. For example,Baker Hughes developed the Remote Log DisplaySystem (RLDS) that runs off their ECLIPS data-acquisition system.4 It provides real-time log anddata transmission in one direction, from the well-site to remote workstations, where basic inter-pretations can be performed and presentationscustomized. Transmission is over a wide range ofcommunications channels from dial-up modemsto satellite links.

Intranet Multipoint Data Delivery A powerful alternative to point-to-point datadelivery is a multipoint-oriented system.5 Such adynamic system has been in operation in theUnited States at the Schlumberger data deliveryhub in Sedalia, Colorado for 15 years. Althoughthe transmission system and the server hardwareand software systems have evolved over time,the overall concept remains the same.

Schlumberger currently has nine such datadelivery hubs worldwide: Sedalia, Colorado;Calgary, Alberta, Canada; Muscat, Oman; Cairo,Egypt; Aberdeen, Scotland; Stavanger, Norway;Perth, Australia; Kuala Lumpur, Malaysia; andCaracas, Venezuela.

The TransACT system is the name given bySchlumberger to the whole data delivery frame-work built around these hubs. This frameworkwas specially developed to allow secure and reli-able transmission, monitoring, processing, track-ing and delivery of oilfield data to clients,supporting final product creation (prints, tapes,CDs) and file filtering and format conversionwhere necessary (below).6

Complicating factors in the oilfield data trans-mission environment—real-time and post-jobdata transmission often across poor, low-band-width links—mean that off-the-shelf transmission

Schlumberger

Web data server

Data management center

Data delivery hub

SNIC-FTP server

Fax machine

Product deliverycenter

An

adri

ll

Data acquisitionsite

Express delivery

Data services center

Operator desktop

> TransACT framework. This data delivery framework provides a common data delivery system to all segments of the E&P industry, serving all forms of data produced, facilitating data integration and collaboration as appropriate on a global basis—thus making a positive impact on the workflow from thewellsite to production optimization. Data delivery starts at the data acquisition site (upper left), where the data are sent through the TransACT data deliveryhub to the operator desktop (upper right) or other destinations such as data services centers (middle left ) and data management centers (lower middle).The operator receives data through the Schlumberger Information Network (SINet) using one or more options including the Schlumberger Network InterConnect (SNIC) service, facsimile, product delivery centers and secure portals to the Internet such as the Web data server.

methods generally are not suitable. The TransACTdata delivery framework, uses custom solutions toprovide reliable and secure transmission capabili-ties from the acquisition sites, to increasethroughput using new data-compression algo-rithms and to function robustly, with error-recover-ability, particularly over low-quality links. Theproprietary TRX transmission software for efficientdigital data transfer, the protocol used in mostSchlumberger data transmission systems, is oneof these custom solutions.7

An example shows how the TransACT datadelivery system works. A logging engineer at awellsite using a Web browser can send a set ofinstructions—called “orders”—to the TransACTdata delivery hub (above). Once the order

is submitted and the data files are transmitted to the hub, the engineer is free to leave the wellsite. Authorized field engineers and locationmanagers can log onto the TransACT hub fromany location and at any time to monitor theprogress and status of deliveries. The hub thencarries out the order, redistributing data andgraphics files to clients, partners and other desti-nations as required through a variety of meansthat best suit the needs of the clients. TransACTdata delivery includes the following options:

SNIC—The Schlumberger Network InterConnect (SNIC) service is one of the most popu-lar data delivery options used in the TransACTsystem. It provides a connection between theSchlumberger Information Network (SINet), thewide area network (WAN) provided by Omnes,

> Acquisition-site data communications. The map shows Inmarsat service coverage (top) for allregions to approximately 70˚ latitude in both the northern and southern hemispheres. MAXIS MultitaskAcquisition and Imaging Systems logging trucks (bottom) maintain data communications to theSchlumberger Information Network (SINet) using connections through a variety of communicationlinks, including Ethernet, Inmarsat, VSAT, ISDN and cellular modems.

Winter 1999/2000 47

4. More information about ECLIPS can be found at theBaker Hughes Web site (http://www.bakerhughes.com).

5. Murchie S, Provost JT, Burke T, Karr G, Alam SO,Scheibner D and Citerne A: “Innovations in GlobalElectronic Data Delivery,” paper SPE 56686, presented atthe SPE Annual Technology Conference and Exhibition,Houston, Texas, USA, October 3-6, 1999.

6. For more information and the latest news on datadelivery, log on to the Schlumberger Web site(http://www.connect.slb.com).

7. Clark R, Danti B, Guthery S, Jurgensen T, Kennedy K,Keddie J and Simms D: “Building a Global Highway forOilfield Data,”Oilfield Review 5, no. 4 (October 1993): 23-35.

48 Oilfield Review

and the operator’s workstation. The data areplaced onto the SNIC system, which is a secureFTP server, and operators access it through adedicated private line between their networksand the SNIC system. Access control istwofold—first, the Schlumberger e-commercefirewall, which limits access to the systembased on IP address, and second, a user-nameand password, which also are also required toaccess the server.

Product delivery center—Often the operatorneeds prints, reports, films, CDs and tapes deliv-ered. These can be generated at a productdelivery center (PDC) located physically close to the operator and are delivered by surface mail or courier. The PDC produces faster deliveryand higher quality final products and reduces thetime required at the wellsite by the acquisitioncrew (below).

Archive—Schlumberger intranet communica-tion between the TransACT system and theLogDB database allows automatic flow andarchiving of data from the TransACT hub into theSchlumberger data-management system forarchiving and future retrieval of the data (above).

Fax—Digital facsimiles are widely used fordata delivery. Since the transmission originatesfrom a digital graphic file, the fax on the receivingend is of high quality. This digital faxing, or digi-fax, is popular because the client does not needspecial equipment. Besides, fax machines com-monly use continuous length paper, making themsuitable for well logs. The limitation of faxes isthat data cannot be reused or modified easily.

DataLink DropBox delivery—This deliverymode places the data onto a Web server in asecure enclave—virtually located outside theSchlumberger intranet—to be easily accessiblethrough the Internet. Operators are notified by e-mail when data arrive from the field. The opera-tors simply use their Web browser with anaccount name and password to retrieve the datausing standard HTTP or secure HTTPS protocols.This delivery option has the benefit of allowingnumerous users, including partners, to accessdata simultaneously from different locations.

> Product Delivery Center (PDC). This photographshows the busy Aberdeen PDC, which makesthousands of prints every year. These facilitiescan copy data to color prints, film, digital audiotape (DAT) and compact disk read only memory(CD-ROM) for final delivery.

Data delivery hub

An

adri

ll

Schlumberger

Web data server

Data management center

Data acquisitionsite

> The TransACT-to-LogDB data flow. Data management is an integral part of the log data deliveryframework. The TransACT data delivery system periodically copies log data files (DLIS and PDS) fromthe central data communications hub (lower left ) to the data management archive system using theTRX transfer protocol together with a descriptive text file. The log database receiver process thenuses the descriptive text file to import log data files to be scanned, loaded and archived. During theauto import, scan, load and archive process, the database system continually updates a HypertextMarkup Language (HTML) report (upper right ), which the operator consults from the central data communications hub.

Electronic mail—E-mail is often used toattach small digital graphics or minimum datasets. The maximum attachment size allowedvaries by company, but generally is on the orderof a few MB, which limits the use of this deliverymechanism. In addition, since e-mail messagesare not normally encrypted, data security couldbe compromised. E-mail is used to notify usersthat other more secure data delivery methodshave been used and successfully completed. Forexample, whenever a SNIC or DropBox datadelivery transaction is completed, an e-mail mes-sage is automatically sent to the user.

The TransACT framework is completely trans-parent to the data user. Schlumberger data aresent in a timely, efficient and fully traceable man-ner with minimal human intervention. Many ofthe tasks formally performed manually at the fieldacquisition site have now been transferred to andautomated by the TransACT data delivery hub(right). This has a large impact on both perfor-mance and efficiency. The compression andrecovery features provided by the TRX protocolensure that transfers are fast and reliable. Sincethe transfer proceedings are completely transpar-ent, the engineer can focus more attention on logquality control.

After the engineer generates the correspond-ing TransACT order, the data delivery hub auto-matically completes the required data deliveryprocess. A typical order may include data conver-sion, multiple format data delivery and anynumber of the available delivery methods (right).By the time the logging tool reaches the casingshoe, data transmission is finished. The deliveriesare completed within minutes with no interven-tion besides mailing the CD and hard-copy printsgenerated in the PDC to the operator.

0

2000

4000

6000

8000

10,000

12,000Monthly Individual Orders

0

20

40

60

80

100

120

140

1601999 Monthly Transfer Volumes in GBytes

Jan Mar May July Sept Nov

Jan Mar May July Sept Nov

> Statistics on North American TransACT activity. Graphs show the monthlynumber of data-delivery orders (top), and total volume of data transferred(bottom) by the TransACT data delivery hub located in Sedalia, Colorado. This hub handles all of the US market, both land and offshore.

Convert incoming data from DLIS into LAS format, filtering out all nonessentialchannels as indicated by the operator.

Deliver the LAS file to the operator's geologist in Houston through SNIC(automatic e-mail notification of file availability).

Deliver graphic copies of the log to three partners through the DropBox utility(automatic e-mail notification to partners). They can securely retrieve the logsthrough the internet using their Web browsers and the corresponding user-namesand passwords.

Fax a copy of the log to the operator's drilling office to quickly evaluate casingand cementing needs.

Send color prints of the logs, a CD containing the original DLIS file, the LAS-filteredfile and other digital graphics—such as quality control and crossplots—generatedin the Houston PDC to the operator's office.

Notify the Schlumberger Field Services Manager by e-mail after the abovedeliveries have been successfully completed.

Automatically archive all data in the LogDB database.

> A Typical TransACT order.

Winter 1999/2000 49

50 Oilfield Review

The user does not need a special application on his or her desktop computerto view and download data. Virtually everyone has a Web browser.

The data are made available to any authorized user. This is an improvement over the point-to-point data delivery mechanism, in which data arrive only at a single user’s system. Web delivery permits multipoint and simultaneous delivery anywhere in the network.

Firewall problems are avoided. Most operators have ports in their firewalls open to HTTP and HTTPS (encrypted) Web traffic. Data are not ”pushed“ to the user;instead the user ”pulls“ the data back through any firewalls that may be present.

Security of access is maintained. Web servers have standard authenticationand access control mechanisms. These mechanisms usually involveuser-names and passwords or digital certificates.

The user has full control of data delivery and timeliness is assured. If thedata arrive at the Web server in real time, the user can access the dataimmediately. If the user missed the real-time arrival, the data are still there and can be viewed at a later time.

The Web server can provide a single point of contact from multiple oilfieldservices, such as drilling, logging, fracturing and production, easily accessiblethrough a single interface.

> Advantages of Web-based data delivery.

Sperry-Sun Drilling Services also provides amultipoint data delivery system for a wide rangeof rig services and rig sensors including MWD,directional drilling, drilling fluids and pumpingservices. Their INSITE Integrated System forInformation Technology and Engineering soft-ware allows the operator to view and analyzedata in real time in a customized format at therig, or at the office and other remote locations.8

Real-time communications to third-party sys-tems using the Wellsite Information TransferSpecification (WITS) format are supported. Allthe information is contained within an OpenDatabase Connectivity- (ODBC-) compliant data-base. This allows standard commercial applica-tions such as Microsoft Office to have direct accessto the database to generate graphics and reports.

Service companies are not alone in develop-ing multipoint data delivery systems using pri-vate networks. Operators also are developingdirect links between drilling monitoring systemsand data management and interpretation sys-tems. One custom solution uses a single inter-face for operators and different drilling

contractors and service companies. As part ofStatoil’s research and development effort orga-nized in the Wellbore Positioning Project, theDrilling Automation in Real-Time (DART) systemwas developed to connect rigsite data-acquisi-tion systems directly to Statoil’s internal projectdatabase (left). The project objective is todevelop concepts for application integration andreal-time data exchange to enhance multidisci-plinary decision processing, and to enable effi-cient quality assurance and verification ofdifferent field operations.

Choosing a platform-independent solution forthe DART system makes it possible to integratediverse software applications by establishingstandardized on-line data communication andreporting formats. Statoil has finalized the firstworking prototype version of the DART systemcovering MWD and LWD data. An application fordownloading real-time and historical drilling datato the project database is in prototype testing atthe Statoil Gullfaks facilities in the North Sea.The Statoil DART approach is to be as open aspossible to enable a common platform for datatransfer and application integration to be estab-lished with service companies.

Schlumberger

ABC

DEF

XYZ

Other service providers

InterACT

Web Witness

RigLink

DART Link

Baker HughesInteq

Sperry-Sun

INSITE

Wellbore positioning

MWD QA/QC

Landmark

Open Works

WellboreMWD logs

> Drilling Automation in Real-Time (DART) system. Statoil developed direct linksbetween their data management and interpretation systems and drilling monitoringsystems. The DART system is now being used to connect rigsite data acquisitionsystems directly to Statoil’s internal project database.

IBM Global Security and Privacy Serviceshelped Schlumberger evaluate the risksinvolved in providing E&P data delivery over the Internet.1 A team explored the relationshipsbetween common Internet activities, such ascollaboration, production access, publishing ande-business, and the requirements of data deliv-ery in the oilfield environment. This led to anunderstanding of how the major Internet secu-rity hazards, such as information theft, program-ming errors and repudiation could impact datadelivery objectives.

The key security requirements of an E&P datadelivery system, in order of priority, were first,authentication, access control, and confiden-tiality, then data integrity and finally, systemavailability. With a good understanding of busi-ness needs, perils and security requirements,several technology and process objectives wereidentified to achieve a secure Internet datadelivery system:• verification of application security controls

including identification and authenticationand access controls on resources

• an acceptable customer enrollment and regis-tration process that protects Schlumbergerand its clients

• encryption of data to achieve confidentiality andintegrity requirements for data transmission

• formal policies and procedures with respect tooperations, administration and audit.

IBM’s process and policy recommendationswere organized using the framework provided by the British Standard 7799 Code of Practicefor Information-Security Management. The stan-dards in this code are especially valuable forinternational operations.

It is interesting to note that operators havewidely divergent policies with regard to datasecurity, with many companies foregoing datasecurity for efficiency. Many common deliverypractices, such as fax and e-mail, have developedover years as a matter of convenience and effi-ciency, but provide reduced security. In othercases, more secure data delivery options areoften overlooked. For example, when download-ing data from the web-based DataLink DropBox,operators are offered the option to use the moresecure, encrypted HTTPS, rather than standardHTTP. Many choose not to use the encrypteddownload, sometimes because of corporate pol-icy against using HTTPS. In time, data securitywill become as much a part of the oilfield cul-ture as safety, and industry-wide data securityprocedures will become the established practice.

Security for E&P Internet Data Delivery

Winter 1999/2000 51

8. More information about INSITE and INSITE-ANYWHEREcan be found at the Sperry-Sun Drilling Services Website (http://www.sperry-sun.com).

9. Bhatt D, Kingston J, Bragstad H and O’Neill D:“Interactive Exploration,” Oilfield Review 9, no. 4 (Winter 1997): 22-31.

Internet Data Delivery The increased popularity of the SchlumbergerDataLink or DropBox delivery option has led to thedevelopment of an integrated system of Internetdata delivery mechanisms. What makes these sys-tems particularly attractive is that they use widelyaccepted commercial technology, such as Internetaccess and Web browsers (previous page, top).Today, these Web-based oilfield data delivery sys-tems provide commercial-quality security such asencryption and user authentication used inInternet banking and e-commerce (see “Securityfor E&P Internet Data Delivery,” right ).

The InterACT Web Witness data-delivery sys-tem is designed to provide secure Internet accessto real-time logging data through a Web browser.From the IDEAL or the MAXIS wellsite acquisitionsystems, the data are sent in real time to a Webserver. Once the data are at the server, multipleauthorized users can access them simultane-ously, and each user can interactively customizethe visualization of the data from table listings,plots and displays choosing presentation param-eters such as scales, colors and units. This data-delivery mechanism can be deployed either onthe Internet or within an operator’s intranet.

Another example of an across-the-Internetdata delivery system is the SuperVISION servicethat helps operators monitor the progress of seis-mic data-acquisition projects.9 It provides opera-tors with a simple, efficient and secure method tolink to acquisition information such as reports,images, maps, on-line QC-displays and plots,seismic sections and test results—allowingstructured access to these results on demand, atany time of the day or night and anywhere in theworld. The system enables rapid decision-makingbased on acquisition data of the same quality asoperators would be able to see if they were actu-ally present at the acquisition site.

1. For more information about IBM Global Security and Privacy Services, see their Web site(http://www.ibm.com/security/html/consult.html).

Off the West African coastline, the Azobe 3Dsurvey performed by Geco-Prakla was under-taken by the Seisranger survey vessel just 5miles [8 km] from Port Gentil, Gabon in 1999(above). Acquisition commenced late inNovember and was expected to finish by the endof the year; however, the 550-km2 [212-sq mile]prospect was particularly difficult. Being close tothe shore, the water was relatively shallow andhazardous. There was the additional problem ofshipping and fishing in the vicinity of the vesselas it acquired the data. Debris—mainly pampasgrass islands—was continuously washed acrossthe survey area, striking the acquisition streamers.Meanwhile, strong currents aggravated prob-lems by making it more difficult to control acqui-sition equipment. Given these difficult workingconditions, the UK-based support geophysicists

were particularly interested in continuallyreviewing the available information and complet-ing the acquisition project as quickly as possiblewithout compromising data quality. There werefour pieces of critical information: • header plots to monitor cable depth, in order to

ensure optimal amplitude and frequencyresponse of the geological targets

• root-mean-square (RMS) amplitude plots tomonitor cable noise and ensure a good signal-to-noise ratio

• brute stacks, which provided an indication ofthe quality of the data being processed

• navigation and seismic coverage to ensuregood overlap with existing surveys in the areaand to determine whether infill shooting wouldbe required.

The navigation and seismic coverage plotsrevealed an area of incomplete coverage, proba-bly caused by vessel and streamer drifting in thehigh offshore currents (below). The speed atwhich the SuperVISION service helped the geo-physicists monitor these critical data ensuredthat remedial work was carried out immediatelyand did not require a subsequent and costlyrevisit to the area.

Elsewhere, the SuperVISION remote monitor-ing system is helping operators and contractorscollaborate on seismic processing by allowingearly processing results to be viewed on a Web-based browser at each step. On a NorthSea project, TransCanada is using theSuperVISION service to provide images of resultsof various velocity models on their prestack

52 Oilfield Review

Azobesurvey

site

Gabon

A F R I C A

> Location of a marine seismicsurvey in Gabon.

Sequence 1

Sequence 1Sequence 3Sequence 5Sequence 7Sequence 9Sequence11

Sequence 3Sequence 5Sequence 7Sequence 9

Sequence 11

> Seismic coverage plot. The map shows the ship’s position (white curves) and amount of survey coverage. The light area in the map (upper right) shows that early in the thirdsequence an area of incomplete coverage occurred. Strong currents that day most likelydeflected the survey vessel or streamers.

Wellsite

AcquisitionFront end

Acquisitionand controlsoftware

Central storage Data analysis Data analysis

Datamanagement

Operator engineering offices Schlumberger and third-party offices

Cable

Gauges

Data delivery

Firewall

> Multiple-user permanent monitoring data-delivery system. The architecture of the WellWatcher daily system enables multiple userswith a Web-browser application to display and analyze data from permanent downhole sensors. The data-acquisition system at thewellsite sends the data in a real-time continuous mode and in a near real-time mode on a scheduled basis or at user request. The twomodes are not exclusive. The data delivery system supports all the WellWatcher acquisition systems such as the WellWatcher, thePumpWatcher and multiphase FloWatcher systems.

Winter 1999/2000 53

depth migrations and to assess the effectivenessof postmigration processing. The Web-basedresults are faster than sending paper sectionsand provided the operator with the ability to eval-uate each model and phase of the processing.Herman Kat, a scientist from TransCanada, says,“SuperVISION is a good way to monitor seismicacquisition and processing, and offered easyaccess to data when required. It offers a muchbetter view of the available data than e-mailattachments. Data delivery through theSuperVISION system is a real step ahead.”

Effective data delivery also is important tolong-term reservoir management. Pressure,temperature and flow data from downholegauges installed permanently on the completionstring have been available for more than 20 years (see “Downhole Monitoring: The StorySo Far,” page 20). The value of these data can be increased with new systems to access ondemand downhole monitoring data and surfacemeasurements on the Internet (above). Real-time data acquisition and delivery to multipleusers through the Web-based WellWatcherdaily wellsite production monitoring and com-munication system can help operators exploitthese measurements to optimize reservoir andproduction performance.

BP Amoco and Reda Production Services havebeen using the WellWatcher daily system in theNorth Sea to monitor surface, downhole andelectric submersible pump parameters since thebeginning of 1998. The BP Amoco Forties fieldhas been producing since the early 1970s, how-ever during the last ten years, declining produc-tion has been maintained by secondary recoverytechniques such as gas lift and electric sub-mersible pumps. The Forties field has five plat-forms, Alpha, Bravo, Charlie, Delta and Echo.Most of the electric submersible pumps areinstalled in wells on the unmanned Echo plat-form, which was originally designed withoutprocessing facilities. Remote operation is per-formed from the Alpha platform.

Eight permanent monitoring systems withpressure and temperature gauges have beeninstalled on four platforms. Data from thesesystems are available to authorized BP Amoco,Reda and the WellWatcher engineers located inseparate offices onshore using the WellWatcherdaily Web-browser interface (below). Con-tinuously monitoring parameters such as intakeand discharge pump pressures and temperaturesin real time helps engineers remotely controlelectric submersible pump operation duringcritical startup after a shut-in period. For exam-ple, the ability to monitor electric submersiblepump parameters during power changes andstartup inrush surges avoids operating the pumpunder conditions that might lead to prematurefailure, costly replacement and unnecessary lossof production.

With the availability of real-time data, wellengineers can also correctly differentiate com-pletion problems from pump problems, and thusplan effectively for remedial work. Reservoirengineers can monitor reservoir performance inreal time under static and flowing conditions.Unplanned shut-ins give them the ability to con-duct buildup analysis and observe the effects on

other wells across the reservoir. The electric sub-mersible pump operator can quickly evaluate anypotentially adverse operational condition andadvise on the maintenance of optimal parame-ters for the ‘well system’ asset, thus assuringcontinuing cash flow for all parties.

Operators often seek custom data-deliverysolutions for specific needs. The Norwegian oilcompanies, including Amoco Norge, BP Norge,Norske Shell, Norsk Hydro, Phillips PetroleumCompany Norway, Saga Petroleum and Statoiltogether with the Norwegian PetroleumDirectorate agreed in 1998 to set up a privateextranet called the Secure Oil Information Link(SOIL) (next page). The objective was to facilitatedata exchange more easily throughout the life ofa field as these operators work closely togetherwith service companies. Making individual con-nections between all involved parties is not con-sidered a good solution for efficient data delivery.Before SOIL was established, data would be sentto operators either on tape or by transferring datato the operator’s server using dedicated lines.

Transferring large files, such as seismicdata, through the Internet can be problematicdue to bandwidth limitations and link stability.

File transfers through dedicated lines raiseissues related to both the additional workneeded to establish these lines as well as net-work security. A custom solution like the SOILextranet can provide better bandwidth, link sta-bility and security than the Internet, while stilllinking business partners. Such a network pro-vides a big advantage for data-delivery systemssuch as the SuperVISION service used to monitorseismic data-acquisition and processing projects.In 2000, two new state-of-the-art secureSuperVISION gateways have been installed toprovide data-delivery communications betweenSchlumberger and its clients. One of these gate-ways is dedicated to serving clients through theSOIL network. This server is located at the at theOslo Solutions Center, Norway, where SINet islinked to the SOIL network. The other gateway,serving clients through the Internet, is located atthe Schlumberger Connectivity Center (SCC) inHouston, Texas.

Petrolink Services Ltd. have also been provid-ing data-delivery systems in the North Sea sincethe early 1990s, and have been widely used bymajor operators. Since then, Petrolink hasexpanded their services worldwide. Although notdirectly involved with data acquisition, they arecontracted by operators to manage data trans-mission from the wellsite to the operator’sonshore offices. They offer rapid postacquisitiontransmission of all wellsite data from any land oroffshore site to any location in the world usingdial-up and fixed-link satellites, microwave, radioand regular telephone networks.10

Today, these systems consist of secure Webservers connected to the Internet running LotusNotes software. This program enables data to beautomatically presented for both uploading anddownloading through the Internet using abrowser that provides encrypted data exchanges.Data are held as individual records within astructured database, enabling the user to sortthem by date, record type, rig or well. With pri-vate networks the Web server can be connecteddirectly to a wellsite or other remote location,permitting operators to interact directly with theserver and upload data that can be accessed overthe operator’s own intranet. Alternatively, theserver can be connected through a firewall toanother server with a direct connection to theInternet, to allow data transmission and accessto anyone with the correct security profile.

54 Oilfield Review

> Electric submersible pump witness display. The electric submersible pump witness display-menu (top) identifies the field, well and all available data channels and the time of displayrange for the selected field and well. The display selected in this example shows the electricsubmersible pump intake pressure (blue) and temperature (red) taken every 10 sec over aone-hour interval. A zoom feature enables the operator to expand any area in the chart tolook at details of the parameter-monitoring history. 10. More information about Petrolink Services Ltd. can be

found at their Web site (http://www.petrolink.co.uk).

Winter 1999/2000 55

Baker Hughes Inteq also has a browser-basedsystem—using multiple secure Web serversaround the world—called RigLink, that facilitatesdata communications between the wellsite andremote displays in the operator’s office. LikeRigLink, the INSITE-ANYWHERE system allowsusers to view information available from Sperry-Sun’s INSITE real-time data analysis system withan Internet connection and a Web browser.

Balancing Security and UsabilityThe evolution of electronic E&P data deliverymechanisms will continue to be driven by a mix-ture of market needs and technological growth.The Internet will play a larger and more complexrole, and two features—usability and security—will dictate its growth for oilfield data delivery.Although usability and security usually have con-flicting implications—the more secure a givensystem, the more complex and cumbersome tooperate and vice-versa—the industry will finditself striving for an optimum resolution.

In addition, as corporations become moreaware of electronic security issues, the data-delivery infrastructure must provide technologicalsolutions to allow remote expertise and decision-making to be performed securely. Examplesinclude the use of user names and passwords tolog into data repository sites, and the use of

encryption, especially when data must move overthe Internet. More sophisticated methods ofauthentication—such as Public Key Infrastructure(PKI) and smart cards—are employed for moreadvanced systems.

Most operators’ networks are usually pro-tected by an e-commerce firewall. As a result,transactions are more secure. Each firewall willblock all incoming unauthorized file transfers anddata deliveries from an outside network unlessspecifically programmed to accept such transac-tion by means of poking a “hole” in it. This alter-native is generally not accepted by mostInformation Technology (IT) organizations, giventhe security breach that it implies.

Technology advances in the field of VirtualPrivate Networks (VPN) indicate that soon VPNwill be the option of choice to work around thisproblem. Through such technology, firewalls willbecome more “intelligent”—rather than justblindly rejecting all incoming transactions, andthey will prompt the originators of the transmis-sion to identify themselves.

Identification or authentication can be donethrough “digital certificates”—a digital incarna-tion of the passport for virtual travelling—issuedby a trusted agency in a form of a lengthy stringof digital characters. Like real passports, digitalcertificates contain certain characteristics that

allow the firewall—the immigration office of thevirtual world—to verify that they have not beentampered with. In this way, firewalls can ensurethat a trusted individual, generally an authorizedemployee, is originating the incoming transac-tion, and grant access to the network. The mostsecure and convenient way to store a digital cer-tificate is within a smart card, and it probablywon’t be long before a smart-card reader isincluded in all commercial computers.

Since the information must still travel throughnonproprietary links, it will be necessary to usecodification or encryption to ensure its integrity.In this arena, PKI technology is expected be themost commonly accepted option. Here, each indi-vidual will be issued—once again by a trustedagency—a personal and digital “private key,” ofwhich only one copy exists. The agency also willmake available through the Internet a matching“public key.” The public key is used by anyone toencrypt data, which once encrypted can beviewed only by the holder of the matching privatekey. One convenient and practical place to storethe private key will be in the smart card.

Down the Data HighwayThe last few years have been rich with manycommunications and data-delivery developmentsin every domain of the E&P industry. The world israpidly assimilating advances in Web-basedtransactions that are modernizing the way wework together. Browser-based delivery interfacesare impacting much of the decision-critical work-flow. Optimizing the flow of data to those whouse it is one way to increase operating efficiencyand reduce cost.

Advances in communications technology aredriving the shift from an asset-centered to anexpert-centered—or decision-centered—workprocess, facilitating collaboration, integration,knowledge capture and, as a result, superiordecision management. In an upcoming article inthe Oilfield Review, we will complete the dataservices story by showing how advanced dataintegration and interpretation platforms are com-bined with 3D-visualization technology to helpoperators and service companies make moreinformed and knowledgeable decisions in thedomains of reservoir evaluation, developmentand management. —RH

Norsk Hydro

Phillips Petroleum Schlumberger Well Services

KvaernerOil and Gas

Services

Statoil, USA

SOILSecure Oil Information Link

Statoil, Norway

> Norwegian Secure Oil Information Link (SOIL) network. The Norwegian SOIL network is abranch network linking together oil companies and service providers within the Norwegianoil industry. This high-speed extranet provides an infrastructure for secure communicationsand data services. Examples are secure e-mail, directory services, secure Web services and e-commerce.