APPLICATION OF NEW PRODUCTION LOGGING TOOLS TO WATER PRODUCTION CONTROL: A CASE STUDY

S. Cantini, Schlumberger - L. Corbetta, M. Firinu, ENI - AGIP Division

Copyright OMC 2001. This paper was presented at the Offshore Mediterranean Conference and Exhibition in Ravenna, Italy, March 28-30, 2001. It was selected for presentation by the OMC 2001 Programme Committee following review of information contained in the abstract submitted by the authors. The Paper as presented at OMC 2001 has not been reviewed by the Programme Committee.

ABSTRACT

GHOST* and DEFT*, innovative production logging tools, complemented with traditional measurements, were used for the first time in Italy in the Well Trigno 6, for water production diagnosis.

The GHOST tool is able to quantitatively identify gas and hydrocarbons in multiphase flows using 4 optical sensors, measuring the refractive index of the fluid surrounding the tool.

The DEFT tool can instead discriminate between water and hydrocarbons, measuring the fluid resistivity by 4 electrical sensors.

Both tools have the sensors evenly spaced in the pipe cross section, and their position in space is accurately known through the use of an integrated relative bearing sensor. The individual sensor measurements are used to build an image of the downhole flow in the well.

Trigno 6 (located in San Salvo gas field) is producing gas since 1967 from a sandstone multilayer reservoir ; its production, facing a strong decline, was characterised by a very unstable gas flowrate (ranging from 50.000 Sm3/d to zero) and a high watercut (average water production of 7 m3/d).

An intervention aimed at reducing water production was needed and the well seemed to be a good candidate as placed in a high structural position in the reservoir.

Lengthening the life of this well could allow the recovery of reserves which otherwise would have remained unproduced.

A production log was recorded and the image of the new production logging tools clearly identified the water entry points. A through tubing plug was set to isolate the water producing intervals.

The total operating time of the above intervention was 11 hours.

The intervention has turned out to be very positive as all the goals were reached : gas flow rate is now very stable and water production has significantly decreased. In addition to that, the intervention has had a pay out time of less than a month.

Considering that in Italy most of the gas producing wells have typology and problems similar to Trigno 6, this innovative and cost effective solution to control water production has a relevant applicability potential.

INTRODUCTION

Gas production in Italy is concentrated offshore in Adriatic Sea and onshore on the middle/ southern part of the country. A great majority of the gas fields are multilayer and multipool type, made up of sequences of sand layers, each a few meters thick, interbedded with shales.

The depth of these reservoirs varies between 800 and 3000 meters. In the late life of

* Trademark of Schlumberger

the well water production may occur. Managing water production in multilayered reservoirs is complex and can influence both the final recovery and the economics of the whole project. Several types of intervention can be used to control water production; in this article an innovative method to diagnose of water entry points and an efficient technique to shut off water producing zones without the need of a workover are presented.

BACKGROUND INFORMATION

SAN SALVO FIELD HISTORY

Well Trigno 6 belongs to San Salvo gas Field, located 50 Km north of the town of Campobasso (Central Italy). The gas Field has been discovered in 1956 and its primary gas production, up to 1999, is 13.619 MSm3. The primary gas production history of the field is shown in Fig. 2.

In 1982 the primary gas production stopped due to the fact that the wellheads flowing pressure balanced the export line pressure. Some pools were consequently converted to storage ; on this purpose 45 more wells have been drilled. The Field has altogether about 160 wells by now. In 1985 two compressors were installed to lower the export line pressure and the primary gas production could start again in the southern part of the Field (dynamically disconnected from the northern part, used for gas storage). Production is now carried out through six wells ; Trigno 6 is one of them.

SAN SALVO FIELD GEOLOGY

The San Salvo Field has a multilayer, gas bearing reservoir. Reservoir rock is a pliocenic sandstone, of turbiditic origin, alternated to shales. The petrophysical characteristics of sand levels are generally good, with a porosity ranging from 25 to 28% and a permeability between 50 and 400 mD.

The trap is of a sedimentary type (see Fig. 3).

It is possible to identify on the area of the Field 14 gas bearing levels, belonging to Candela-Torrente Tona Formation, named respectively from B to L. Well Trigno 6, before the intervention, was producing from levels B and C (see Fig. 4) .

TRIGNO 6 WELL DESCRIPTION

Trigno 6 is a vertical well drilled in year 1961, reaching a total depth of 1642.2 mRT. It is completed with a single tubing string ( 2" 7/8 plus 3" 1/2 OD, see Fig. 9).

Gas is produced through several perforated intervals in the 7" production casing between 1096.5 and 1161.5 mRT, corresponding to the following layers :

level B 1147 – 1161.5 mRT

level C 1096.5 – 1141.5 mRT

Until November 1999 no intervention was done to modify the original completion scheme.

PRODUCTION HISTORY OF THE WELL

The well started producing in January 1967 ; primary gas cumulative production of the well, till November 1999, is 384.6 MSm3.

The well is operated by the Centrale Gas of Cupello (CH) where its gas is transported by line and treated.

Its production history, shown in Fig. 6, can be briefly summarised as follows :

The well began producing gas with an average flow rates of 100.000 Sm3/d (with occasional peaks of

500.000 Sm3/d), with a stable gas production and no watercut.

Wellhead flowing pressure, which was 109 Kg/cm2 at production start-up, slowly dropped to 34 Kg/cm2, equalising the line pressure. For this reason the well stopped producing in March 82.

In 1995, after the line revamping, the well started producing again but with very unstable gas flow rates and high watercut; wellhead flowing pressure has dropped from 42 Kg/cm3 (in 5/95) to 21 Kg/cm3 (line pressure is now 19 – 20 Kg/cm3).The month before the intervention (from 15/10/99 to 15/11/99) wellhead delivery parameters had been daily checked. As it can be seen in Fig. 7, gas flow rate ranges between 60.000 Sm3/d and less than 10.000 Sm3/d and water flow rate has reached up to 14 m3/d.

It is important to point out that the critical gas flow rate required for water unloading is around 38.000 Sm3/d . If gas flow rate goes below the critical value (possible as the well head flowing pressure is nearly equal to line pressure) water quickly settles down in the bottom hole flooding the well and interrupting production. At this point recurring interventions are required to restore proper delivery conditions.

INTERVENTION

REASONS FOR INTERVENTION

Looking at the production history of the well from 1995 (Fig. 6), it appears that its management was extremely difficult and a water shut off intervention was needed for the following reasons:

- Irregular gas production, ranging between 60.000 and 10.000 Sm3/d with occasional well flooding (when the flowrate went below the critical value). The flooding required recurring intervention of purging the well or lightening the liquid column (using foam sticks).

- Strong water production due to the acquifer rise in levels B and C which implies :huge problems of surface water management (two water tubs of 5 m3 storage, unable to collect a daily production with peaks of 14 m3 )

- Additional costs due to water transportation and drainage.

Other wells present in the area, LC4 and LC8D, have similar problems , but Trigno 6 was chosen as a candidate for the intervention as it is placed in an upper structural position (see Fig. 5).

INTERVENTION DESCRIPTION

The intervention on the Well Trigno 6 was performed on 19/20 November 1999 by electric wireline, deploying the tools through tubing. Initially, a production log was recorded with a PSP* (Production Services Platform) string (see Fig. 10). The PSP* offers, in addition to basic measurements, the possibility to combine the new DEFT* and GHOST* sensors to clearly identify water entry points in the corresponding producing intervals. All the tools above described were combined in a single tool string of 9.9 m. length.

The total operating time, comprehensive of rigup, rigdown and log recording, was 5 hours.

Once the water entry points had been identified on the log, a through tubing bridge plug (MPBT) was run and set at 1112.5 m. to plug the undesired producing intervals. Some cement was dumped on the top of the plug with two runs of "cement dump bailers", to increase its differential pressure rating (see Fig.1). The total operating time for the three runs (MPBT* and bailers) was six hours.

TOOLS DESCRIPTION

GHOST

The GHOST* (Gas Holdup Optical Sensor Tool ) is a new production logging device to enable the direct detection and quantification of gas in multiphase flows. Four optical sensors mounted on probes, deployed 90 degrees apart on the arms of a centralizer like tool, measure the refractive index of the surrounding fluid. The tool consists of a sonde section, an optoelectronic section and an electronics section.

GHOST PHYSICS OF MEASUREMENT

Optic fibers connect a light source with the 4 sensors on the probes, and the amount of light refracted back is dependant on the fluid surrounding the sensor. A photo diode is used to record the intensity of the refracted light. If the probe is in gas, the refracted light has high intensity, while if it is in oil or water the intensity of refracted light is low (see Fig.11). Local gas holdup is determined by the ratio of the time during which the sensor detects gas respect to the total time (see Fig. 12).The sensor are evenly spaced in the pipe cross section, and their position in space is accurately known through use of an integrated relative bearing sensor. The individual sensor measurements are used to build an image of the gas flow in the well.

DEFT

The DEFT* (Digital Entry Fluid Imager Tool) has 4 electrical sensors that make independent holdup measurements of the multiphase fluids in each quadrant of the pipe cross section, discriminating between formation water and hydrocarbons.

The DEFT* electrical sensors can be run on a standalone tool or integrated on the spinner cage arms of the PSP*, Production Services Platform (see Fig. 10). The PSP* is a compact tool string designed to provide basic measurements (GR,CCL, pressure, temperature, caliper, fluid density, flowrate) and electrical probe measurements, with a total length of 5.62 m. only.

DEFT PHYSICS OF MEASUREMENT

The DEFT* sensor measures the direct current resistivity of the fluid surrounding its tip. Each sensor generates a binary output signal when it pierces impinging droplets of oil or gas in water-continuous phase or, conversely, water droplets in oil or gas continuous phase. Since water is the electrically conductive medium in oil or gas producing wells, the probes only discriminate between water and hydrocarbons. Since water resistivity is inversely proportional to its salinity, the sensors cannot distinguish water from hydrocarbons when salinity is as low as 1000 ppm (at 100 DegC).

The probe signals allow computation of a local holdup measurement and the number of hydrocarbon bubbles arriving at each probe (bubble count).

The local water holdup is computed from each probe. It is the ratio of the time spent by the probe in water to the total scanning period. Conversely, oil or gas holdup is the ratio of the accumulated time while the probe detects hydrocarbon to the total scanning period (see Fig. 12) .

A relative bearing measurement is used to identify the orientation of each probe in the wellbore.

MPBT

The Mechanical Plug Back Tool (MPBT) provides a way to plug off in casing sizes from 4" ½ to 9" 5/8 in a highly efficient and low cost rigless operation by running the plug through the completion tubing and hydraulically expanding the plug in the casing. High pressure differential integrity is achieved by dumping cement on top of the plug using through tubing cement dump bailers. The tool varies from 1 11/16" to 2 1/8" in external diameter before setting depending on the casing size in which the plug has to be set. The MPBT* service compliments the evaluation services provided by PSP* and RST* to identify zones of water production and then provide immediately the solution to decrease water production without the need of a rig.

LOG INTERPRETATION

A log down pass was initially recorded for tools calibration and depth matching with the well shut-in. Subsequently, the well was put in dynamic conditions and a log up pass was recorded through the perforated intervals to identify the water entry points (see Fig.13).

The PSP* log shows the basic production logging measurements (pressure, temperature, caliper, fluid density, flowrate) and the GHOST* and DEFT* images, with relative gas/water holdups.

From an interpretation point of view both basic and new sensors (GHOST* and DEFT*) measurements show a water level at 1109.6 m., below which all the perforations (from 6 to 10) have to be considered non productive. Immediately above 1109.6 m., a water entry in correspondence with perforation 5 and at the very bottom of 4 can be clearly identified from the DEFT* and GHOST* images.

Despite some water production from the bottom, it was decided to keep perforation 4 open and set a plug for water shutoff immediately below (m. 1112.5), as the highest gas production originates from this set of perforations (see spinner curve and related interpretation).

CONCLUSIONS

TECHNICAL RESULTS

Production start-up after the intervention was on 21st November 1999 ; after a quick purge that gave more than 400 lt. of water, the well began to produce with the following parameters:

-gas flow rate settled at about 50.000 Sm3/d (this value is still maintained).

-produced water ranges between 0.4 and 0.1 m3/d.

The intervention has therefore turned out to be very positive for the following reasons :

-regular gas production has been restored : the well is always able to produce with flow rates higher than water unloading rates ; furthermore gas production has greatly increased.

-water production has been strongly reduced, in addition to the problems connected with its surface treatment and drainage expenses.

The month after the intervention (from 21st November 1999 to 22nd December 1999) wellhead delivery parameters had been daily checked (shown in Fig. 8). This permitted to compare, in a quantitative manner, cumulative gas and water production the month before and after the intervention:

Before intervention After intervention

Gas 790.8 KSm3 1.316.5 KSm3

Water 105.5 m3 9.94 m3

ECONOMICAL RESULTS

The cost of the intervention was 83.000.000 Italian Liras (1 US$= 1927 Italian Liras at 31 December 1999) , split as follows :

Production Log/MPBT/bailers 60.000.000 Liras

Slickline 23.000.000 Liras

The evaluation of the profit due to a rise in gas production during the following month is :

525.700 Sm3 * 204 Liras/Sm3 = 107.242.800 Liras

In addition, the money saved for the decreased amount of water treatment is:

45.000 Liras/m3 * 95.56 m3 = 4.300.200 Liras

The pay out time of the intervention has therefore been less than one month

NOMENCLATURE

Kg/cm2 =Kilograms per square centimeter

KSm3 =Thousands standard cubic meters

m =meters

m3/d =cubic meters per day

mD =Millidarcies

mRT =Depth in meters referenced to rotary table

M Sm3 =Millions Standard cubic meters

Ppm =Parts per million

Sm3 =Standard cubic meters

Sm3/d =Standard cubic meters per day

DEFT =Digital Entry Fluid Imager Tool

GHOST=Gas Holdup Sensor Tool

MPBT =Mechanical Plug Back Tool

PSP =Production Services Platform

RST =Reservoir Saturation Tool

ACKNOWLEDGEMENTS

The authors wish to thank the Management of Agip Ortona and Schlumbergerfor permission to publish this paper. They also acknowledge the assistance rendered by the colleagues in AGIP and Schlumberger. Special thanks to Marcos Domingues, the logging engineer.

REFERENCES

1. Bamforth S., Besson C. et al., "Revitalizing Production Logging" , Oilfield Review, Winter 1996.

2. Didek M., Pedron B. et al, "New Production Logging Tool Enables Problem Well Diagnosis", 1995.

3. Vittachi A., North R.J., "Application of a New Radial Borehole Fluid Imaging Tool in Production Logging Highly Deviated Wells" , SPE paper 36565,1996.

Figure 1 – Schematic of intervention on Well Trigno 6 . From the indications of the Production Log , the well was producing water from Perfo 5 and bottom of Perfo 4 (left). A Through Tubing Bridge Plug was set between Perfo 4 and Perfo 5 (right), in a highly efficient and low cost rigless operation by running the plug through the completion tubing and hydraulically expanding the plug in the casing. High pressure differential integrity is achieved by dumping cement on top of the plug using through tubing cement dump bailers,also run by wireline.

Figure 2 – Primary gas production history of San Salvo gas field from production start up, up to 1999.

Figure 3 – Sedimentological model of S. Salvo Field.

Figure 4 – Cross section.

Figure 5 – Structural map top level B.

Figure 6 – Production history of well TRIGNO 6 from production start up until the water shut off intervention (November 1999) .

Figure 7 – Monitoring of wellhead parameters of well TRIGNO 6 one month before the intervention of water shut off.

Figure 8 – Monitoring of wellhead parameters of well TRIGNO 6 one month after the intervention of water shut off.

Figure 9 – Simplified completion scheme of Well Trigno 6 before the Water Shut Off intervention.

Figure 10 – The PSP (Production Services Platform) tool string in the configuration represented above was used to log the Well Trigno 6. The PSP is a compact tool string designed to provide basic measurements (GR,CCL, pressure, temperature, caliper, fluid density, flowrate) and can be combined with the GHOST tool. The DEFT electrical sensors are integrated on the spinner cage arms of the PSP. The total length of the string run in Trigno 6 was 9.9 m..

Figure 11 - GHOST principle of measurement - Optic fibers connect a light source with the 4 sensors on the probes, and the amount of light refracted back is dependant on the fluid surrounding the sensor. A photo diode is used to record the intensity of the refracted light. If the probe is in gas, the refracted light has high intensity, while if it is in oil or water the intensity of refracted light is low .

Figure 12 - Holdup determination principle for DEFT electrical sensors (left) and GHOST optical sensors (right). The DEFT sensors holdup output is determined by the ratio between the time the sensor detects hydrocarbons against the total time. Similarly, the GHOST sensors holdup output is determined by the ratio between the time the sensor detects gas against the total time. The 4 outputs are then averaged to give the total holdup.

Figure 13 – Production Log recorded in Well Trigno 6 in dynamic conditions. On the composite log shown above are presented the traditional measurements complemented with the image of GHOST and DEFT sensors (tracks 3 and 7 respectively) and computed holdups (tracks 5 and 9 respectively). The images clearly show a water level at 1109.6 m. and water produced from perforation 5 and bottom of perforation 4.