OTC 15177 Well Intervention Using Rigless Techniques Sandeep Khurana, Granherne Inc.; Brad DeWalt, Granherne Inc.; and Colin Headworth, Subsea 7 Inc. Copyright 2003, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, TX U.S.A., 5-8 May 2003. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.

Abstract An important factor in the overall success and cost of an offshore well intervention depends significantly on the choice of the equipment including downhole tools and surface units. Using a conventional workover rig for well intervention is expensive and may not be appropriate in many circumstances. Additionally, intervention of a subsea well can further increase the costs due to the requirements of a floating vessel and subsea systems to access the wellbore.

This paper systematically categorizes downhole applications that are performed during well intervention. It reviews techniques such as Wireline, Coiled Tubing (CT) and Hydraulic Workover (HWO) that do not require use of a conventional workover rig and have capability of performing downhole applications in live (under pressure) wells. Included are guidelines for selection of these rigless techniques for the various downhole applications.

The rigless techniques are further reviewed in relation to subsea well intervention. The emphasis is placed on selection of a floating vessel along with subsea systems to connect to the well. The paper includes a discussion on market trends that are directed towards either reducing intervention costs or minimizing its frequency.

Introduction

Well intervention is defined as remedial operations that are performed on producing wells with the intention of restoring or increasing production. A well may require intervention due to flow restrictions, changes in reservoir characteristics, sand production, mechanical failure, or to access additional hydrocarbon pay zones. Downhole applications that are performed during well interventions include well surveillance and diagnostics, implementation of reservoir management techniques, completion repair and re-entry drilling to reach new producing intervals. This paper defines and categorizes these downhole applications for use in determining guidelines for selection of rigless techniques.

The choice of techniques and equipment to perform the downhole applications determines the mechanical and economic success of a well intervention job. A conventional workover rig comprising of a derrick, rotary table and heavy machinery can be used to perform well intervention. However mobilizing an offshore rig and its associated support operations is expensive. Furthermore, using a rig generally requires killing the well (i.e. displacement of fluids in the wellbore to counteract the downhole well pressure) and creates the risk of damaging the reservoir. Well intervention methods that do not require a rig and have the capability of being performed on live wells (without killing the well) are the focus of the discussion herein. These rigless techniques include Wireline, Coiled Tubing (CT) and Hydraulic Workover (HWO). The paper discusses the equipment and characteristics of these rigless techniques and provides guidelines for the selection of these techniques for various downhole applications.

Downhole there is little difference in the tools that are deployed for dry (platform) wells versus subsea wells to remedy flow problems. But subsea well intervention in deepwater is typically much more expensive than dry well intervention due to the high day rates of floating vessels and the equipment costs of the subsea systems that are required to access the wellbore. The selection of the floating vessel and the subsea system is therefore critical.

The paper identifies various types of floating vessels along with subsea systems that can provide subsea well intervention. Market trends to achieve low cost well intervention are discussed in light of the increase in rigless-technique equipment; a rapidly growing number of subsea; and with the supply and demand of conventional rigs. Also reviewed is the parallel trend of smart well technology that is focussed at reducing well intervention frequency.

Downhole Applications In well intervention, downhole applications are activities that are performed in the wellbore to remedy production problems or otherwise increase production from the well. Most of these applications are typically a less complex version of well construction and completion phase work.

Coherent industry definitions for downhole applications relevant to well intervention are not readily available. Industry definitions as they exist today focus on the well construction and completion phase, and differ vastly based on major oil service providers’ definition that is based on their packaged product service lines. In order to comprehend the

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scope of well intervention applications, twelve major categories are identified in downhole applications. These applications are depicted in Figure 1 (except SCSSV Repair) and are described as follows:

♦ Logging

Well logging is typically performed to gather reservoir data or to perform diagnostic testing of reservoir or wellbore conditions. Well logs are typically categorized as either cased hole (the reservoir investigated has been cased through) or open hole (the reservoir investigated is uncased).

♦ Perforating Perforating may be required to produce from new zones or to open plugged perforations from the existing completion.

♦ Well Cleaning Well cleaning is used to remove flow restrictions, such as formation fill or scale. It also includes sand clean-outs or sand washing to sweep settled sand deposits out of the well bore.

♦ Fishing Fishing operations are conducted to remove undesired downhole equipment such as screen pipe or stuck wireline tools. This application is usually conducted along with other applications.

♦ Fluid Displacement Fluid displacement techniques consist of the circulation of fluids, such as nitrogen, through the wellbore to initiate production or improve transport and flow properties of the reservoir.

♦ Thru-Tubing Sand Control Thru-tubing sand control helps to prevent sand from entering the production stream through the use of filter media, installation of screens or liners or the placement of resin materials.

♦ Remedial Cementing/Conformance Remedial cementing consists of injecting a cement slurry under pressure to a specific interval within a wellbore to repair the primary cement job. The procedure can also be used as a conformance technique to seal zones or to shut-off water or gas inflow.

♦ Selective Stimulation Stimulation improves the permeability near the well zone by acidizing or fracturing the reservoir with fluids using high injection rates and pressures. It is referred to as “selective” as a specific zone is selected to perform stimulation in order to improve well recovery.

♦ Thru-Tubing Completions Small diameter tubing acts as a velocity or siphon string to keep marginal wells unloaded, or as a production string to isolate damaged or defective production tubing. It can also be used as an injection string for gas lift.

♦ Artificial Lift Services Artificial lift equipment is installed to establish or to assist production in wells where bottom hole pressure is insufficient to obtain the desired production rate.

♦ Re-Entry Drilling Re-entry drilling improves production by deepening wells or by drilling horizontal laterals to produce from other pay zones.

♦ Surface Controlled Subsurface Safety Valve (SCSSV) Repair SCSSV repair involves retrieving and replacing a malfunctioning surface controlled subsurface safety valve.

A single downhole application or multiple applications

may be required to fully correct a well problem. Pulling of the production tubing is considered to be a major workover of a well requiring a conventional workover rig, and therefore not included in the above applications.

The frequency of well intervention that will be performed during the life of a field is difficult to predict, since the decision to intervene a well is dependent numerous variables, including reservoir characteristics, infrastructure and economic considerations. Figure 2 ranks each of the downhole applications in order of their relative frequency as seen in industry, including both dry and subsea wells. Stimulation and remedial cementing/conformance applications are the most frequent reasons for well intervention. From this data, it is interesting to note that well intervention is most often performed to address reservoir specific issues, rather than to repair downhole mechanical equipment and completions. Rigless Techniques and Surface Equipment The downhole applications discussed above can be performed using a conventional workover rig. However, a rig generally requires killing the well which creates a risk of damaging the reservoir. Techniques such as Wireline, Coiled Tubing (CT) and Hydraulic Workover (HWO) are generally less expensive than a rig and can be performed on live wells. These techniques are differentiated based on the method and equipment used to convey the downhole tools. Figure 3 shows surface equipment for these techniques. The surface equipment for these techniques is smaller in footprint area and lighter in weight compared to a rig. The details of the rigless techniques and surface equipment are discussed below. Wireline. Wireline involves running and pulling tools and equipment into and out of the well by the use of a continuous length, small diameter solid or braided wire mounted on a powered reel at the surface. This can be done on a wellbore that is still under pressure. Typical wireline operations include perforating, logging, cleaning wells, and dumping cement.

Most wireline surface equipment units are self-contained skids that consist of the wireline reel, power supply and associated control and connection equipment. Wireline is subdivided into two categories: ♦ Electric Line (E-Line)

The wire used in E-Line is a steel armoured electric cable that has the ability to transmit well logging data continuously to the surface. The size of the wire ranges from 7/32 inches to 15/32 inches depending on the mechanical strength and number of electrical conductors.

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Since the weight of the tools is used to pull the wire into the well, E-Line is difficult to use in highly deviated or horizontal wells. This can be overcome with electric powered downhole wireline tractors that pull the E-line into the wells or by using E-Line in conjunction with a coiled tubing unit. The surface equipment for E-Line surface equipment includes the wireline reel, lubricator, BOP (blow-out preventor), power source and measuring device. A sophisticated seal grease injection system is also required. Typical dimensions of the unit for a Gulf of Mexico (GOM) offshore skid are approximately 8 feet wide by 15 feet long with an average weight of 10 tons.

♦ Slickline (S-Line) Slickline uses a solid wire with no electric conductor and is therefore a purely mechanical device. The most common diameter sizes are 3/32, 7/64 and 1/8 inches. A new generation of slickline systems includes an advanced measurement system and downhole measurement tools that have more versatility than a standard mechanical system. They are able to transmit information on the location of the memory log taken inside of the well. Because of these additional features, they are sometimes referred to as electro-mechanical intervention. The surface equipment for S-Line is the same as E-line except that the smaller diameter wire results in a lower package weight and a smaller winch. The new slickline surface equipment includes additional equipment such as advanced measuring systems and data logger. Typical dimensions for an offshore GOM skid are 8 feet wide by 10 feet long, with a weight of approximately 5 tons.

Coiled Tubing (CT). Coiled tubing involves inserting a continuous and a flexible steel pipe into a well bore to convey various well servicing tools and to circulate fluids. Steel coiled tubing is made from strips of high-strength steel that are rolled and seam welded. The tubing is flexible enough to be coiled onto a reel, with diameters that range from ¾ to 3-½ inches. Higher wall thicknesses and the development of new alloys have increased the strength of coiled tubing to allow it to withstand extreme pressure loadings and have improved its resistance to stress corrosion cracking. Advances are also being made in the area of light-weight composite coiled tubing.

CT surface equipment units are self-contained hydraulically powered workover units that provide substantial time and cost savings when compared to using a conventional workover rig. The major advantages that CT offers include:

♦ Faster running speeds into and out of a well since the

operator does not have to stop to connect or disconnect each joint of pipe;

♦ Reduced rig up and trip times; ♦ Ability to continually circulate fluid through the pipe

while the tubing is being lowered into and out of the hole; ♦ Localized delivery of downhole fluids, increasing

production tubing life and preventing contamination of acid from tubing scale;

♦ Ability to work on live wells; and

♦ Ability to perform many wireline services can be performed in highly deviated and horizontal well bores by installing an E-Line inside coiled tubing.

The basic surface equipment of the CT are the coiled

tubing reel, tubing injector head, lubricator, blow out preventor (BOP), power packs and control console.

A CT unit is defined by the pull capacity of the injector head. The snub capacity (pushing in live wells) is about 50% of the pull capacity. The market has equipment with maximum pull capacities ranging from 10,000 lbs to 120,000 lbs (commonly identified as 10K to 120K equipment). Higher capacity translates to capability of the CT to work with larger tubing sizes or longer tubing lengths. For example, a 15K unit typically carries about 8,000 feet of 1-¼ inches, whereas an 80K unit is capable of running 2 inch tubing to 15,000 feet depth or 2-⅞ inches tubing to 10,000 feet.

The offshore skid size depends on well depth and the tubing size. A general dimension for 1-¾ inches diameter, 15,000 feet long coiled tubing unit for a GOM vertical well application is 30 feet wide by 30 feet long with a weight of about 50 tons. These skids can be temporarily installed on the platform to perform work or provided on lift boats for minimum facility platforms.

Hydraulic Workover (HWO). Hydraulic Workover uses hydraulic cylinders to push jointed sections of pipe into the well, in contrast to the seamless tube used in CT. The pipe can be inserted either under pressure or after killing the well. The advantages of using HWO over CT are that HWO can handle more complex jobs involving deeper reservoirs with higher pressures. HWO has the ability to use tapered pipe and can adjust the pipe length based on reservoir depth. HWO operations however are more costly than that of CT operations. The decision to use HWO instead of CT is dependant on the requirements of the specific application to be performed and the overall economical consideration.

Based on its application in the field, HWO is divided into the following categories:

♦ High Pressure Snubbing

Snubbing refers to pushing pipe into a well under pressure. High pressure snubbing is an area where HWO competes with CT to perform work on live wells.

♦ Hydraulic Rig Assist Hydraulic Rig Assist units assist conventional workover rigs and supplement the work performed by rigs to make the intervention job much more economical. By definition a rig assist unit is not a stand alone type unit and operates only in conjunction with the workover rig.

♦ Major Workover HWO units have the ability to perform a major workover on the well, and compete directly with the work that is traditionally performed by conventional workover rigs. Major workover jobs typically involve the pulling of the production tubing for repairs. The basic components of an HWO surface unit are the

jack and slip assemblies, pipe rack, pipe handling mast and winches, work basket, BOP, power units, operator control

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console, BOP control console and auxiliary equipment such as the accumulator package.

An HWO is classified by the lift force in kips (1 kip = 1,000 lb) and the through bore diameter in inches of the jack. Standard lift capacities range from 120 to 600 kips and the through bore sizes are typically 4 to 13 inches.

The offshore skid size depends on well depth and the tubing size. Typical dimensions for a GOM application are 25 feet width by 50 feet length for the equipment skid and 20 feet by 45 feet for the pipe skid. The total combined weight of both skids is about 200 tons. These skids can be temporarily installed on the platform or provided on lift boats for minimum facility platforms.

Selection Guideline for Rigless Techniques The complexity of the process, the equipment deployed and the cost increases from Wireline to CT to HWO. The selection among rigless techniques is based on the complexity of the downhole application and the overall economics of the intervention. Table 1 provides a selection guideline among these techniques for the downhole applications. Wireline (include E-line and S-line) is mostly used in logging, perforating, fishing, artificial lift services, SCSSV repair, and to a limited extent in well cleaning and remedial cementing. In relation to the intervention frequencies in Figure 2, Wireline cannot perform frequently occurring stimulation and sand control services. On the other hand CT covers most of the downhole applications with a limited competition where HWO may be suitable.

In general, the selection criteria are as follows:

♦ E-line is chosen where a continuous electric supply is needed such as in production logging and perforating. As previously discussed, it is more common to use E-line in vertical wells but it can also be used in horizontal wells with the assistance of a well tractor.

♦ S-line is used when mechanical work can be performed in a cost effective manner using a wire. With the use of battery powered tools and depth location devices, S-line is now able to compete in some areas with E-line.

♦ CT is typically used in situations where fluid circulation is necessary, and to reach highly deviated and horizontal wells. CT can perform numerous downhole applications, and is increasingly becoming a preferred method of well intervention.

♦ HWO is more suitable for high pressure wells than CT and is also used where production tubing needs to be pulled. The choice between HWO and CT is therefore dependent upon the requirements of the downhole application and on the overall economics of the job.

Rigless Techniques in Subsea Well Intervention Downhole applications are identical for both dry and subsea wells. The same rigless techniques can be deployed for both types of wells. However, subsea well intervention in deepwater requires a floating vessel and a subsea system to access the wellbore. The floating vessel not only supports the surface equipment for Wireline, CT or HWO, but should have the capability to handle the subsea system. These are the requirements that determine if the floating vessels can be other

than a rig. It is therefore important to understand the conventional subsea intervention approach of utilizing a subsea riser and the alternative riserless method. Traditional Approach - Subsea Well Intervention. Traditionally, the subsea system has been a rigid workover riser package that provides direct access for the surface intervention equipment. The purpose of a workover riser is to extend the wellbore to the surface to provide well access at the full pressure rating and diameter of the downhole completion. The dynamic pressure seal between ambient and the wellbore is at the surface on the vessel. Figure 4 shows a conventional subsea well intervention from a floating vessel.

A workover riser package consists of steel riser joints attached to the subsea tree through a subsea lower riser package (LRP), which includes blow out preventors (BOP). The workover riser components also include a subsea emergency disconnect package, stress joints, surface tree, circulating hose, control umbilical, control system and associated running and test tools. The bore is made to match the completion size and is typically 4 or 5 inches nominal diameter. Depending on the system, a workover riser may also include a parallel riser for accessing the casing-tubing annulus of the well. The top of the riser is supported by a tensioning system and is designed for installation and retrieval with a derrick and associated handling system. Wireline, CT and HWO operations are performed from designated areas on deck and items attached to the workover riser surface tree, such as the coiled tubing injector can be supported with an additional motion compensation system. Tool strings can also be isolated from vessel motion with heave compensation systems. A workover riser requires passive heave compensation systems with a substantial load carrying capacity that increases with water depth. It also requires a support vessel that is stable in the local sea conditions and a handling system that can deal with large packages, weighing tens of tons, in addition to jointed pipe.

A MODU (Mobile Offshore Drilling Unit) is usually selected for supporting subsea workover operations. Even if a conventional working rig is not required for Wireline, CT and HWO, it is usually chosen for subsea well intervention since the rig on a MODU has the capability to handle workover risers using the same equipment that it uses for its drilling riser system. The use of a MODU for well intervention is often driven by availability in the field between well construction programs. Perhaps the most significant reason MODU are deployed for well intervention is their ability to change work scope in mid job, to carry out heavy workover tasks, such as pulling the completion if the situation downhole proves to be different from what was envisioned when planning the intervention. This occurrence is relatively common, given the remoteness of subsea wells and the consequent lack of downhole information.

MODU, with well construction as their primary function, are not usually a good fit for many downhole applications in well intervention since only a small portion of their total capability is utilized. They can be slower and more costly than a fit-for-purpose unit. In addition, well intervention surface equipment such as Wireline and CT are temporarily assembled on board these vessels, reducing the overall

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efficiency because of the non-productive time required to rig up, rig down, to interconnect to the well and to organize the resources to perform the job.

Alternate Approach in Selection of Floating Vessels and Subsea Systems. Using floating vessels that are not MODU and which do not have marine drilling systems, is recognized as an alternative approach for well intervention. This approach aims to optimize the pairing of subsea access method with a floating vessel to achieve lower day rates for specific intervention capabilities.

The objective is to have substantially lower, floating vessel day rates as compared to a MODU. However, this lower day rate typically comes with the penalty of less intervention capability.

An established example of this is the use of subsea lubricators for wireline intervention from dynamically positioned monohull vessels. This technique has been used for more than fifteen years, particularly in the North Sea and to a lesser degree in the Far East. Figure 5 shows an example of a subsea lubricator. Another established method is to use vessels specifically configured to run workover risers as seen, for instance, over the past several years in the Gulf of Mexico.

Since subsea well intervention involves vessel owners, subsea installation contractors and well service vendors, a coherent definition of various types of intervention has not been established throughout the industry. Table 2 is presented to introduce a well intervention classification based on the type of vessel and the complexity of process as follows:

♦ Support Vessel (Typically a monohull)- Light

Well Intervention A monohull with a free deck area of up to 10,000 square feet that has capability to perform wireline services in conjunction with a subsea lubricator is termed Light Well Intervention. It is also referred to as “riserless” intervention.

♦ Semi-Submersible or Large Monohull – Medium Well Intervention Semi-submersibles or Large Monohull are vessels with deck area of up to 30,000 square feet. They are equipped to perform well intervention services, have the ability to handle rigid workover risers in deepwater and are classified as Medium Well Intervention.

♦ Conventional Workover with a MODU – Heavy

Well Intervention The major well workovers that require conventional rigs to pull tubing strings, perform re-entry drilling, side-tracking, etc. fall under the category of heavy well intervention. This work is carried out using MODU that are either semi-submersibles or monohull vessels outfitted with marine drilling and hoisting equipment.

Market Trends Eliminating the MODU for conventional workover is only the first step in reducing intervention cost. Ensuring that the alternative floating intervention vessel can sustain a competitive edge in overall economics is equally challenging.

Dedicating vessels to well intervention depends on having sufficient market volume to keep the utilization at commercial levels. To date, only one vessel has achieved sufficient utilization (and only in recent years). That vessel is in the UK sector, where the number of subsea wells now exceeds 700.

Instead of a dedicated vessel, an MPSV (Multi Purpose Service Vessel) can be used for well intervention. Such vessels are able to perform other services like subsea installation thereby providing them with a larger market. However, there are commercial pitfalls for such vessels. Outfitting them for multifunctional use can increase the day rate and make them uncompetitive in some or all of their target markets. If surface equipment has to be mobilized and demobilized for each well intervention, additional costs and inefficiencies are introduced.

Another approach is to use low cost vessels that are already commercially successful in their normal market and use them in conjunction with a well intervention system (with as little adaptation as possible) that is specifically designed to match the vessel capability. An example of this exists in the Far East where shallow water subsea wells are left permanently attached to a buoyed riser just below the water surface. A small work boat can tow a short section of workover riser and a surface access buoy to the well site where it is upended and connected by divers to the submerged riser section. The work boat, complete with wireline winch, is moored alongside the riser and is able to carry out well intervention tasks in the benign sea conditions of that region.

Many different designs and concepts have been put forward over the last two decades for non-rig intervention methods that enable the use of lower cost vessels for well intervention. In some cases, these have never got beyond concept level. Some have been taken to prototype stage, some have been tried and abandoned and some have gone on to technical success. Commercial success remains more elusive for the service providers. Such techniques include:

♦ Subsea wireline lubricator ♦ Vessel optimized to run tensioned workover risers ♦ Permanently installed submerged buoyant riser with

removable surface access riser section ♦ Subsea lubricator with compliant guide for CT access ♦ Combined subsea wireline lubricator and injector for stiff

composite wireline ♦ Combined subsea wireline lubricator and wireline winch ♦ Combined subsea CT lubricator and CT injector ♦ Combined subsea CT lubricator, CT injector and CT reel ♦ Flexible intervention riser

Different vessel designs have also been proposed to the industry, by many different companies, to match these various approaches. From a commercial point of view and for meeting the needs of subsea well operators, the most promising of these subsea intervention techniques seek to provide a CT capability in addition to wireline. CT is the most versatile of all rigless techniques and can perform almost all the downhole applications in well intervention. Additionally, CT has increasing applications in well drilling and completion operations and thus the number of CT units is on the rise.

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Figure 6 shows this trend. With CT, the added scope of work capability expands the

usefulness and the potential market volume for a subsea well intervention service. However, the cost and risk of developing and commercializing these subsea techniques runs into many tens of millions of dollars and, in a normal market, relies on a sufficiently high level of demand for the service providers to commit to this level of spending and risk.

A demand for low cost well intervention services is often articulated by Operators but the alternative subsea well intervention market to date has not been attractive for the service providers. Many factors come into play to diminish this market.

The rates for MODU, driven by supply and demand, are a significant determining factor. The start of the subsea well intervention market in the UK sector of the North Sea in the 1980’s coincided with the start of a long period of a depressed MODU market. Operators had no desire to use a limited intervention service when the full capability of a drilling rig could be secured for a similar cost. During this period, specialized well service vessels made technical and commercial sense only where it was possible to put together a campaign covering many wells. The dynamic positioning capability of a typical well intervention vessel allows for a much faster job on a multiple well program than can be achieved with the anchored MODU used in the North Sea. But this is in an industry sector that does not typically plan its well intervention activities to this level. A gradual acceptance of alternative techniques along with the recovery of the MODU market during the 1990’s enabled some service providers to continue in the business in one form or another.

Other factors that play a significant part in diminishing the potential market for alternative subsea well intervention relate to the design and operation of the wells themselves. In the face of a perceived high cost for well intervention, Operators have consistently applied a design and operations philosophy that seeks to reduce the need for well intervention to zero. Even if this has meant increased capital costs or lower recovered reserves, great effort has been put into achieving this goal. Indeed, zero intervention is seen as a normal and accepted design basis for subsea wells.

Another set of factors diminishing the subsea intervention market are the enormous reserves and the prolific producing rates associated with them. Many fields chosen for development, particularly in deep water, are those large in size but with the simplest reservoir structures, which are the type of wells that call out for a zero intervention approach. The most likely intervention requirement for such wells is due to sand control mechanical failures that with current technology require a re-completion of the well, a job that currently can only be done with a MODU.

The size of the well intervention market is extremely difficult, if not impossible, for service providers to predict. Attempts to estimate the number of subsea wells requiring intervention along with an estimate of average days required per intervention and thus predict the market volume are hindered by lack of data. Individual operators have also made attempts to predict their own number of intervention days and have occasionally shared this information with the service providers. However, there is little or no historical data

publicly available to determine the accuracy of the various predictions. It is only possible to look in the broadest sense at what has happened in the past in the well intervention market. Even this does not yield much insight to what the market may be like in the future since a large number of the new subsea wells will be in much deeper water, and will be growing in geographic regions where numbers had been historically low. This picture is further complicated by the consideration that the existence of a low cost well intervention service can itself stimulate the growth of the market.

The growth of worldwide subsea well activity is depicted in Figure 7, which shows the number of subsea wells by region in existence up to 2002 and the predicted number of subsea wells through 2007. This chart shows that the UK sector currently has over 600 subsea wells. Even so, only one vessel has successfully demonstrated the ability to dedicate its services as a specialized well intervention vessel in this area. Norway has over 400 subsea wells and has only seen a couple of specialized well intervention vessel operations to date. North America has over 200 subsea wells and has had occasional work recently for a vessel specially outfitted to run a workover riser. Brazil has over 400 subsea wells yet has never intervened with anything other than a workover riser. Asia Pacific has approximately 100 subsea wells and has had alternative well intervention systems operating for a number of years. These activities are mainly due to long term contractual agreements by field or by the application of Operator owned equipment and technology to specific fields.

All of this does not give much encouragement to those considering risking their investment dollars to provide alternative well intervention services. The market risk is too great, the volume is too low. The market risk appears too great, and the demand too low. This kind of market risk can be mitigated by the Operators if they so choose, much like in the drilling market where deepwater MODU have been built on the basis of long term contracts. The Operators’ requirements could be tied to long term contracts, obligating service providers to take on the technical risk of their services. Most large Operators organize field production operations into separate Asset Teams. It is unlikely that individual Asset Teams for particular fields will have sufficient intervention work to justify a long term contract. Some kind of sharing is needed with other Asset Teams within that corporation or even with other Operators, in either case creating administrative difficulties that would need to be addressed. Smart Well Technology and Future Trends In contrast to the well intervention market, investments have been made, particularly in smart well technologies, to approach the zero-intervention goal. Smart wells allow for real-time data gathering of downhole information. They can also include provisions to control production from various zones from a remote control center. Figure 8 shows details of an example “smart” well. It should be noted that Smart well technology has not seen widespread use yet. Issues related to complexity, reliability and capital costs have led to a cautious attitude by Operators in implementing such solutions except in those cases where the benefits can be clearly established.

Interestingly, even though Smart well technology normally works to reduce the need for well intervention, one aspect

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serves to compliment it. Having the data available from a Smart well helps to build a more certain picture of the current status and any associated production problems with that well. Hence, the data gathered from a Smart well gives greater certainty for selecting an appropriate and targeted intervention response. An intervention service that is only capable of providing wireline, for instance, can be dispatched with greater certainty of success. Selection of a MODU solely to be prepared for any unexpected problems becomes less attractive. Particularly if the specialized well intervention vessel offers significant cost-saving benefits.

Timely well data can also help to improve the timing of intervention activities and provide for better planning, thus improving the likelihood of a successful well intervention. Because of this, a significant amount of intervention work is performed for well surveillance and diagnosis, rather than for remedial action. This increases operating expenses, downtime and has the additional risk of complete data not being available for well intervention planning.

Frequently, well intervention is performed for reservoir management to remedy water influx or gas break out. This becomes even more important in wells with multiple zones, as commingling is generally not allowed by the regulatory bodies. Furthermore, multi-lateral well technology that reduces the number of slots also requires additional reservoir management to ensure that production is maximized from various zones. All the above issues have led to advances in, and implementation of Smart well technologies.

Subsea wells are predicted to double or even triple in number over the next five years or so. A significant part of this growth will be in deep water regions where the cost and availability of suitable MODU is quite high and the availability quite limited compared to that of the North Sea, where the alternative well intervention market first grew. These new deepwater environments should drive the need for alternative well intervention techniques. Specialized well intervention vessels may very well become an outgrowth of this activity. Conclusions ♦ Systematically categorizing downhole applications and

understanding the equipment and characteristics of rigless techniques - Wireline, CT and HWO - establishes a basis for intervention selection guidelines.

♦ The development and use of multi-purpose vessels can be an attractive alternative to dedicated well intervention vessels that are dependent upon the continued growth in subsea intervention demand. Multi-purpose vessels must be appropriately matched to subsea system requirements.

♦ The market is influenced by a growth in subsea wells, especially in deepwater regions, and by a growth in the use of CT for many downhole applications in these wells.

♦ The growth of subsea wells has increased the focus on reducing well intervention costs as well as on minimizing intervention. These goals tend to be mutually exclusive.

Abbreviations BOP: Blow Out Preventor CT: Coiled Tubing E-Line: Electric Line GOM: Gulf of Mexico HWO: Hydraulic Workover LRP: Lower Riser Package MPSV: Multi-Purpose Service Vessel MODU: Mobile Offshore Drilling Unit S-line: Slick Line Acknowledgements The authors would like to thank Dean Fanguy (Baker Oil Tools), Perry Courville (Halliburton), John Misselbrook (BJ Services), Dr. Julie Morgan (Granherne), and Kurt Albaugh (BHP Billiton Petroleum) for their support and guidance on this article and Richard Curnow (Granherne) for sponsoring this work. References 1. Khurana, S., and B. DeWalt, “Well Intervention Using Rigless

Techniques-Poster,” Offshore Magazine, Dec 2002. 2. Scott, R.A.: “Multi-Service Vessels for Deepwater Subsea Well

Interventions,” paper OTC 12947 presented at the 2001 Offshore Technology Conference in Houston, Texas, 30 April – 3 May.

3. Larimore, et al.: “Case History: First Diverless Subsea Slickline Well Intervention Performed in Offshore Vietnam,” paper OTC 8589 presented at the 1998 Offshore Technology Conference in Houston, Texas, 4-7 May.

4. Chitwood, J.E. “Subsea Intervention Requirements,” Deepwater Technology, August 1998, 57-68.

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Figure 1. Downhole Applications

Source: Baker Oil Tools Figure 2. Relative Intervention Frequencies

Source: 1998 OTC 8726 and In-House Market Survey

Occurrences

Thru-Tubing Completions

Re-Entry Drilling

Fluid Displacement Services

Cased hole Fishing

Artificial Lift Services

SCSSV Repairs (inplace)

Well Cleaning

Sand Control Services

Logging & Perforating

Remedial Cementing & Conformance

Stimulation

Services

RELATIVE INTERVENTION FREQUENCIES(Includes Platform and Subsea Wells)

OTC 15177 9

Figure 3. Surface Equipment

Source: Wood Group Source: Halliburton

Source: Halliburton

Wireline - Surface Equipment

10 OTC 15177

Table 1. Guidelines for Rigless Downhole Applications LEGEND: Yes = No = Not Economical = Electric Line Slickline Coiled Tubing

Hydraulic Workover

CASED HOLE PRODUCTION LOGGING & PERFORATING Production Logging (surface readouts) Note 1.1 Running Memory Gauges (incl. bottom hole pressure & temp, & flows) Well Diagnostics: Caliper Run Perforating Casing Note 1.8

WELL CLEANING Sand Clean out or sand washing Note 1.2 Paraffin & Asphaltene Removal Scale Removal Underreaming & Drilling

CASED HOLE FISHING Tool Recovery Tubing Cutting - Chemical Tubing Cutting - Mechanical Milling

FLUID DISPLACEMENT SERVICES Nitrogen Jetting/ Lifting Liquid Displacement

THRU-TUBING SAND CONTROL SERVICES Sand placement as filter media Running Screens Inject Resin Materials

REMEDIAL CEMENTING/CONFORMANCE Cement/ chemical shut-off & profile control Spotting Isolation Plugs Note 1.3 Note 1.3 Setting mechanical plugs Sleeve Shifting Repairing Casing and Tubing Leaks Tubing punching

STIMULATION Remedial Stimulation by pumping fluids (acids, solvents, surfactants) Fracturing (using propants)

THRU-TUBING COMPLETIONS Velocity or Siphon & Injection Strings

Production String

ARTIFICIAL LIFT SERVICES Gas Lift valve Installation/pulling/retrieving Servicing an Artificial lift Pump Inplace Setting/Retrieval of Artificial lift pumps

RE-ENTRY DRILLING Side Tracking Deepening

OTHER SERVICES SCSSV Repair (inplace lockout & WRSV installation)

QUALIFICATIONS

Highly deviated wells Notes 1.4,1.5 Note 1.5

Work in Horizontal Wells Note 1.7 Note 1.3 Note 1.3 High Pressure workovers Note 1.6 Tubing Change Out (Note 1.7) NOTES Note 1.1: Combination of e-line in CT can be used in highly deviated or horizontal wells. Note 1.2: For low differential pressure (100 psi), using a bailer. Note 1.3: For short intervals.

Note 1.4: Can be accomplished for highly deviated or horizontal wells with use of a well tractor.

Note 1.5: Difficult and costly for deviation angle greater than 50 degrees. Note 1.6: High Pressure CT is may be used as it provides time savings compared to HWO.

Note 1.7: Tubing change out is a major workover where HWO competes with conventional rigs.

Note 1.8: Possible with new technology tools, such as E-Fire.

OTC 15177 11

Figure 4. Conventional Workover Operation for Subsea Wells Figure 5. Subsea Wireline Intervention Source: Cameron Source: Oceaneering

Table 2. Floating Vessels and Subsea Systems

Vessel Description Subsea System Technique Downhole

Applications Defined

As Support Vessel: Typically a Monohull Vessel with Free Deck area of up to 10,000 sq ft. Subsea Lubricator Wireline

E-Line and S-Line applications as shown in Table 1.0

Light Well Intervention

Semi-Submersible or Large Monohull: Without marine drilling equipment with free deck area up to 30,000 sqft.

Subsea Lubricator, Rigid Workover Riser

Wireline, Coiled Tubing

E-Line, S-Line and CT applications as shown in Table 1.0

Medium Well Intervention

Conventional Workover with a MODU: A Semi-Submersible or a Monohull having a Derrick and Rotary Table with primary function as drilling and completion.

Workover Riser, Drilling Riser

Can perform Wireline, CT, HWO Rig Operations - Pull Tubing, etc.

Covers all applications as defined in Table 1.0

Heavy Well Intervention

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Figure 6. Worldwide Coiled Tubing Units

Source: ICoTA, Ross, Reed-Hycalog, RJ&A Figure 7. Global Subsea Wells

0 200 400 600 800 1000 1200

North America

Brazil

Norway

U.K.

Africa/Med.

Asia Pacific

Other Regions

Number of Subsea WellsFlowing (up to 2002) (Note 10.2) Construction/Pending (Note 10.3) Possible (by 2007) (Note 10.4)

Source: The World Subsea Report 2002-2006 (Douglas-Westwood and Infield Systems)

Worldwide Coiled Tubing Units vs Total Available U.S. Drilling Rigs

400600800

100012001400160018002000

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

Coi

led

Tubi

ng

Uni

ts

400600800100012001400160018002000

Drill

ing

Rigs

Coiled Tubing Units Drilling Rigs

8% C/T Annual Growth

-1% Drilling Rig Growth

OTC 15177 13

Figure 8. Well Details for a Sample “Smart” Well

Source: Well Dynamics

Network Splitter Isolation Unit (SIU)

SCSSV

Gas Lift Device

Wet Disconnect UnitZonal Isolation Packer

ICV with Sensors

Production Packer

SmartWells - SCRAMS™

SCSSV Control Flat Pack with Single Hydraulic and Single Electrical Dual Flat Packs each containing a Single Hydraulic and Single Electrical Line