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Liquid Casing® products non-invasive nature were extensively evaluated in a laboratory test program carried out by STIM-LAB Inc. in Duncan, Oklahoma, (File Number SL 1815.).

The formation evaluation studies used two types of formations with a 2% (7 lb/bbl potassium chloride (KCI) brine containing 4 lbs/bbl of Liquid Casing® and polymers of either Xanthan gum or Xanthan gum plus, and some polyanionic cellulose (PAC). The properties of the fluids tested are given in the following table.

Properties of Polymer Based Fluids in 2% KCI Brine with 4 LBS/BBL Liquid Casing®

Parameter Xanthan Gum Xanthan Gum/PAC
FANN 600, cps 44 31
FANN 300, cps 34 20
Apparent Viscosity, cps 22 15.5
Plastic Viscosity, cps 10 11
Yield Point, lbs/100 sq. ft 24 9
Gel Strength, 10 sec, lbs/100 sq. ft 14 4
Gel Strength, 10 min, lbs/100 sq. ft 20 6
API Fluid Loss, ml 12.7 16.8

The flow studies were conducted on two contrasting cores. One core was a tight Berea sandstone, approximately 50 millidarcies, and the other, a high permeability Brady sandstone approximately 1,000 millidarcies.

The cores were saturated with the brines and then the initial permeability was determined to oil, Klearol, followed by the polymer/Liquid Casing® fluid until a pressure differential of 500 psi or higher was achieved. The core was shut in for 3 hours, and the initial return permeability determined to the oil. A KCI solution was flushed across the core and a final permeability to oil was determined. The results of these experiments are summarized in the following tables:

Formation Damage Testing for Liquid Casing® in a 2% KCL Brine with Xanthan Gum

Initial Perm. Initial Oil Perm. Final Oil Perm. After KCI Flush % Original Perm.
59 md 32 md 60 md 100 md
910 md 240 md 900 md 99 md

Formation Damage Testing for Liquid Casing® in a 2% KCL Brine with Pac/Xanthan Gum

Initial Perm. Initial Oil Perm. Final Oil Perm. After KCI Flush % Original Perm.
59 md 25 md 59 md 98 md
900 md 380 md 780 md 87 md

The flow rate across the core face in these experiments was very low, at about 0.02 ft /min, consequently, the filter cake resembled a static condition rather than a dynamic one; which is the reason why the KCI flush was remarkably effective as it helped to physically disperse the cake. Usually with a polymer filter cake, a drastic treatment such as acid would be needed in order to significantly regain permeability.

These studies show that the Liquid Casing® can quickly form a filter cake which will prevent the invasion of the polymers into the core. A simple mechanical flushing action fully restores the core to its original permeability. These results demonstrate the non-damaging nature of Liquid Casing®, which ensures that the polymer remains in the filter cake rather than penetrating the core.

STIM-LAB Inc. in Duncan, Oklahoma, has recently evaluated Liquid Casing® under simulated field conditions. The study used a kill-fluid formulation where Liquid Casing® was incorporated into a polymer-based formulation.

The test was carried out with equipment designed to evaluate formation damage under dynamic flow conditions of the fluid. The test fluid was in contact with a sandstone core, with an effective permeability of about 250 md at 250 °F, with laboratory-processed North Sea seawater. The core was mounted in a Hassler sleeve under a closing pressure of 1,500 psi. The test fluid flowed past the face of the core with a differential pressure of 1,100 psi across the length of the core. The filtrate was collected in a pressurized container with 100 psi back pressure so the actual pressure drop across the core was 1,000 psi. Both the fluid and the core is heated to the required temperature. The filtrate volume was also determined as a function of time in ml/min.

The polymer-based kill-fluid was formulated with 15 ppb of Liquid Casing®, 3 ppb of Xanthan gum polymer, and 8 ppb of modified starch. The fluid and core were heated in a series of stages at temperatures ranging from 200 to 350 °F, during different time frames in order to determine the dynamic fluid loss.

The test results are summarized in the following table:

Conditions Stage 1 Stage 2 Stage 3 Stage 4
Temperature 200 °F 250 °F 300 °F 350 °F
Time at temperature 4 hrs 4 hrs 5 hrs 1 hr
Dynamic Fluid Loss ml/min 0.01 0.01 0.01 0.4

These results show that the fluid rapidly forms a seal at 1,000 psi and drastically lowers the fluid lost to the formation. It can be concluded that the fluid was effective at temperatures up to 300 °F and displayed no signs of degradation. As the temperature was increased to above 310 °F, there was some indication of deterioration in performance,. However, a seal was maintained as material, which had been stored at the elevated temperature, moved onto the filter face, although the dynamic fluid loss had increased.

At the end of the analysis, the core was cooled to 250 °F and it was back flowed with seawater at a differential pressure of only 1.3 psi, resulting in 92% permeability regain.

These laboratory tests established that Liquid Casing® would be effective in a polymer based fluid at temperatures above 350 °F, and that the filter cake can be easily removed by back flowing the well at very low pressures and with minimum damage.

The test results confirm the field experience and observation established by a number of operators.

It is worth noting that the temperature parameters in this study were limited by the thermal stability of the biopolymers. The NAPC in the Kavala offshore area in northern Greece has used Liquid Casing® to kill wells with high levels of hydrogen sulfide and bottom hole temperatures of 290 °F.

A twenty-eight-day marine BOD was determined by a procedure following the OECD Guideline for Testing of Chemicals 301D - Ready Biodegradability: Closed Bottle Test modified to marine conditions and carried out by Cross and Bevan Water Services, Bedford, England. The biological "seed" was obtained from the River Crouch Estuary, as recommended by the Ministry of Agriculture, Fisheries and Food, and the artificial seawater prepared from Marine mix, which was used as the diluent. The salinity of the dilution water was 33.6 g/l NaCl and the pH was 8.0.

Other analytical methods were performed as defined by the Standing Committee of Analysts, Department of the Environment. Concentrations of dissolved oxygen were obtained by Winkler titration using sodium thiosulphate solution.

The results of the twenty-eight days' marine biochemical oxygen demand (BOD) study are summarized in the following table:

Product Sample Concentration of Test Material (mg/1) Num. of Days BOD mg 02/1 Sample BOD mg 02/1 Sample
Liquid Casing® Fine 5 5
15
28
0.40
0.80
1.00
80
160
200
Liquid Casing® Coarse 10 5
15
28
0.50
1.20
1.50
50
120
150

The Chemical Oxygen Demand (COD) were similar for both products: 1.30g O2per g for Liquid Casing® Fine and 1.059 02per g for Liquid Casing® Coarse.

The degradation calculated as a percentage of the measured COD is as follows:

Product Sample 5 Days 15 Days 28 Days
Liquid Casing® Fine 6.2 12.3 19.4
Liquid Casing® Coarse 4.8 11.4 14.3

The OECD Guidelines 301D suggest that a material reaching 60% degradation during the twenty-eight days BOD test is to be considered as readily biodegradable. The protocol is usually applied to water-soluble substances, but the guidelines indicate that materials of low solubility may be tested as well.

Liquid Casing® Fine and Liquid Casing® Coarse are both derived from a source of cellulose and are insoluble. The COD test values were similar for both products, with Liquid Casing® Fine (1.30 and 1.05 9 02 per g of Liquid Casing® Fine and Liquid Casing® Coarse respectively). The BOD figures were low, giving relatively low percentage degradation for both substances, (19.4% for Liquid Casing® Fine and 14.3 % for Liquid Casing® Coarse).

However the rate of degradation is constant during the test, which indicated that the degradation is continuing at the end of the twenty-eight days BOD test period.

It can be concluded that both Liquid Casing® Fine and Liquid Casing® Coarse are biodegradable but only slowly under marine conditions. However, the test was carried out with a non-specific microbiota, and it is probable that a conditioned flora would produce a greater degree of degradation. The freshwater biodegradability of a substance cannot be deduced from a marine evaluation; nevertheless it is sometimes higher than that obtained under marine conditions.

The toxicity of Liquid Casing® was performed by Weintritt Testing Laboratories, Project Number 319-12-5808.

Liquid Casing® was suspended in seawater and the survival of Mysid Shrimp (Mysidopsis Bahia) was determined over a period of ninety-six hours.

The test results are as follows:

Concentration of Liquid Casing® (ppm SPP) % of Mysid Shrimp Surviving 96 hrs.
CONTROL 98
100,000 98
300,000 90
500,000 87
700,000 88
1,000,000 75

The 96-hr. LC 50 for the sample of drilling fluid was greater than 1,000,000 ppm suspended particulate phase (SPP).

The conclusion was that the Liquid Casing® has an LC 50 of greater than 100% SPP or much greater than the 3.0% minimum SPP specified in the NPDES permit. The material can be considered non-toxic by the NPDES guidelines.

August 1991 edition

Driller tests solution to stuck pipe problems

Preventative drilling fluid treatment alternative to diesel fuel pills

Jack C. Estes; consultant, Buford Gill; Grace Drilling Company

Stuck pipe is more than just a nuisance - it is a costly problem for operators and contractors. It is especially frustrating to the people on the rig who are keeping drilling fluids within specification, and keeping the drilling pipe moving. There are about as many reasons for pipe getting stuck as there are drillers who have been stuck. Years ago, there were fewer reasons, and all of them boiled down to just one reason - "bad mud." It was easy to blame the mud, when it weighed several points more than required, and solids control equipment was just about non-existent or barely working.

What's to blame? Today, good solids control equipment is available, and the means of using it for maintaining low solids muds have been widely taught. It is indeed difficult to blame bad mud anymore. In blaming the mud, we are really blaming ourselves. So what causes stuck pipe, when running a first class drilling operation?

1. Sloughing shales

2. Keyseat

3. High differential pressure

4. All of the above

5. None of the above.

If one or more of the first four is selected, the answer is correct. But if the last one is selected, then that person probably has had the experience of placing a bit or tool into an under gauged hole or indeed has bad mud. Sloughing shale problems are usually treated by using a combination of chemical and mechanical methods. Keyseats are strictly mechanical problems, although mud lubricants do sometimes help. High differential pressure between the mud column and the formation pressure is the big pipe grabber. The wellbore tubulars simply get stuck in the mud cake formed on the side of the hole, and are held there by the force created by the mud column pressure against the area of pipe in contact with the mud cake.

Study of 48 wells

At a 1987 industry forum on New Orleans, a major operator reported on the results of a study on 48 stuck pipe wells during the past three year period in the gulf of Mexico: 60% were attributed to mechanical causes, and 40% were attributed to differential pressure. Spotting an oil-based mud pill in turbulent flow was the favorite treatment. Spotting was used on 80% of high differential pressure between these wells. About.40% of these came free during the first 48 hours. Most of these came free when the pill was pumped within 16 hours of becoming stuck. Only 10% were freed after being stuck for over 96 hours. Jarring or washover procedures were tried on only 20% of these wells. Pipe strings were easier to free in larger holes, with 90% of 12.25 inch or larger holes freeing up after oil pill treatment, or jarring, or both. Small holes, where the drill string tubulars are close to hole size, tended to remain stuck.

Second study

Another study was conducted by Grace Drilling during the following year on onshore wells. Grace experienced getting stuck about 100 times in 18 wells. This was in a sequence of pressure-depleted horizons and high-pressure horizons, and normally pressured horizons. The mud weight necessary to maintain well control exerted a pressure differential against the depleted zones that would grab the drill or the pipe, even when it was kept in motion.

Grace Drilling managers tried many available materials without much success against this differential pressure sticking. One material that produced some success was called Liquid Casing, produced by Gabriel International. The next 20 wells were drilled with fewer sticking problems.

In this area of Louisiana, deeper depleted reservoirs at 5,000-6,000 ft are overlaid with shallower reservoirs at 2,500-4,500 ft, which are still under secondary recovery operations, causing shallow high pressure zones. Mud weight must be raised above ten ppg to prevent saltwater flows. Differential pressure sticking almost always occurred on corrections, even when the pipe was kept moving.

Diesel pills

Typically, drillers would spot a 25-50 barrel diesel pill, and pull free in a time period ranging from minutes to up to 12 hours. Drilling began again, and after several hundred feet, the drill pipe stuck. The procedure was repeated.

The drilling plan normally called for drilling a 12'//4-in. hole to 2,000 feet and setting 9 5/8-inch casing. This was usually done with no problems. The wells were drilled out with water, and sometimes saltwater flows between 2,500-3,500 ft were encountered. The saltwater flows were shut off by raising the mud weight to 10.2-10.4 ppg.

Occasionally, 40-50 bbl of diesel fuel were added as a precaution to avoid getting stuck, particularly be fore trips. However, the pipe stuck anyway. At deeper depths, 8,000-10,000 ft, a pill of ten to 11 ppg of Black Magic was spotted and bumped one-half bbl every hour or two. If not free in 36 hours, the driller ran a free point, backed off, and tripped in jars.

Special treatment

The Liquid Casing material was used during a washover fishing operation. Several hundred 25-pound sacks of the material was mixed in a 1,000 bbl mud system. The action resembled a cased-hole situation.

Later, 150 sacks of the Liquid Casing® Fine was mixed with 80 sacks of a companion product called Liquid Casing® Coarse. These treatments helped stop the differential pressure sticking. There after, the drillers continued to mix eight sacks into the suction tank prior to each wiper trip, or when pulling out of the hole. By knowing where the sticking zones were, the suction pit mud was pre-treated just prior to drilling into troublesome formations. Typical treatments ranged from 12-48 sacks of Liquid Casing® Fine with eight to 18 sacks of a companion material called Liquid Casing® Coarse. Grace drillers found that circulating these pills also helped in working through tight spots in the hole.

The lighter treatments were used as a pill to spot around the drill collars while running a survey. This action was effective in reducing sticking while waiting on the survey. The heavier treatments were run to condition the hole for the casing.

The most cost effective concentration appears to be around eight ppd of Liquid Casing® Fine, combined with an equal or greater amount of Liquid Casing® Coarse. However, in lost circulation zones, higher concentrations appear to raise the pressure gradient where losses occur. The mud remains pumpable at high concentrations.

Hole plastering

One location was staked on a previous trash dump site. There was concern about the hole washing out beneath the rig. Twenty pounds per bbl of Liquid Casing with an additional 30 pounds per bbl of mud was used to drill some 435 ft of fill, in order to set conductor pipe. This plastered the weak hole so that it remained in gauge and gave no problems.

Another technique found useful was while drilling through the Smackover. About 40 bbl of Liquid Casing® Fine and Liquid Casing® Coarse at 25 ppb were mixed, and then pumped in at quantities of 5-6 bbl during any drilling break in the Smackover. Then, the mixture was spotted around the bottom-hole assembly before tripping out to log the hole.

Using the techniques described in this article, the use of Liquid Casing during simultaneous-lost circulation and kick control procedures, made the operation quicker and safer.

It is rather strange that the Liquid Casing does not appear to lower fluid loss, but stops sticking as if the mud had zero-fluid loss. The manufacturer claims this is because the processed cellulose particles are not intended to treat the mud, but to actually prevent a thick mud cake from forming on permeable formation walls. So, laboratory fluid loss tests are not useful in evaluating its effectiveness.

This special sealing action allows for easier coring and better drill stem tests, sealing as well as controlling seepage and fluid loss of whole mud to weak formation zones. Getting stuck drilling, coring, drill stem testing, or running pipe, generally costs 20-48 hours in rig time. Using preventative measures proved to be a cost-effective method to reduce this trouble time.

Today, with new rules concerning mud disposal, there are alternatives to the risk of contaminating the mud system with diesel spotting pills.

AUTHORS

Jack C. Estes is a principle with the Tulsa, Oklahoma-based consultaitcy of Sills, Underwood, & Estes, specializing in environmental problems in drilling and production operations.

Bill Patton is the drilling manager for Grace Drilling Co., based in Houston.

Bufford Gill is a field superintendent for Grace Drilling Co., based in Brookhaven, Mississippi

Reprinted from the August 1991 edition of Offshore Copyright 1991 by PennWell Publishing Company

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Prudhoe Bay Rig Workovers: Best Practices for Minimizing
Productivity Impairment and Formation Damage

C.G. Dyke, BP Exploration Operating Co. Ltd., and D.A. Crockett, ARCO Alaska Inc.

SPE Members

Copyright 1993, Society of Petroleum Engineers, Inc.

This paper was prepared for presentation at the Western Regional Meeting held in Anchorage, Alaska, U.S.A. • 26-28 May 1993.

This paper was selected for presentation by an SPE 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 Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A. Telex, 163245 SPEUT.

ABSTRACT

A field wide review of rig workovers was carried out for the Prudhoe Bay reservoir to enable a set of 'best practices' to be drawn up and implemented. Particular emphasis was placed on well killing, together with the minimisation of formation damage and loss in productivity index associated with rig workover operations. Clear conclusions emerge which have a significant impact on productivity as well as reducing total workover costs.

The results of this case history are of direct relevance to all workover operations, detailing how cost effective well killing can be performed with the minimal productivity loss.

INTRODUCTION

The Prudhoe Bay field, located on the North Slope of Alaska, is the largest reservoir in the USA with initial reserves of approximately 11 billion barrels. It is jointly operated by BP Exploration (Alaska) Inc. and Arco Alaska Inc. First production was in 1977 and the field is now off plateau. Approximately 75 rig workovers are performed each year to maximize the steadily deteriorating well productivity.

To help minimize any avoidable productivity impairment and formation damage arising from these rig workovers, a field wide review of past workover practice was performed. A wide range of workover strategies have been used within the four years covered by the review. These included killing with LCM, living with losses, as well as bullheading or circulating the well during the initial kill. This variation in past practice enabled a wide range of well killing issues to be addressed, as well as assessing the extent of any productivity impairment associated with previous rig workovers. Arising from this, the review's objective - a set of best practices for future rig workovers, was compiled.

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Preventing Lost Circulation in Severely Depleted Unconsolidated
Sandstone Reservoirs

Aziz Ali, SPE, Amoco Trinidad Oil Co.; C.L. Kalloo, SPE, Tucker Group of Companies; and

U.B. Singh, SPE, Amoco Trinidad Oil Co.

Copyright 1994 Society of Petroleum Engineers

Original SPE manuscript received for review March 11, 1991. Revised manuscript received Sept. 20, 1993. Paper accepted for publication Dec. 14, 1993. Paper (SPE 21917) first presented at the 1991 SPEIIADC Drilling Conference held in Amsterdam, March 11-14.

Summary. This paper discusses the field application of a blend of lost-circulation materials (LCM's), in a water-based drilling fluid to drill through multiple severely depleted, unconsolidated sandstone reservoirs. Simple laboratory tests are documented to show the sealing effectiveness of the LCM blend. Major benefits of the LCM blend include lost-circulation prevention, elimination of intermediate drilling-casing strings, and substantially lower well costs.

INTRODUCTION

Lost circulation is one of the oldest, most time consuming, and costly problems encountered in drilling a well. Off the east coast of Trinidad, the problem is no different. Lost circulation, or loss of returns, is defined as the loss of drilling fluids or cement slurries into the formation. Generally, four types of formations are responsible for lost circulation 1: (1) natural or induced formation fractures, (2) vugular or cavernous formations, (3) highly permeable formations, and (4) unconsolidated formations.

The industry has developed three types of agents to combat lost circulation: (1) bridging, (2) gelling, and (3) cementing agents; the type used depends on the operational phase of the well. 2 All these types of agents have been used to combat lost-circulation problems in wells offshore the east coast of Trinidad. In this area, bridging agents are far more effective than cementing or gelling agents for handling lost-circulation problems. Bridging agents can be classified as fibrous, flake, granular, or blended.3 Although all these bridging agents have been used, the blended type seems to cure lost circulation best offshore Trinidad.

Most of the east coast producing fields contain multiple unconsolidated sandstone reservoirs with permeabilities from 50 to 100 md. These reservoirs, which have been partially or severely depleted because of hydrocarbon production, lie below virgin-pressured water-bearing sands and, in some instances, above virgin-pressured hydrocarbon-bearing reservoirs. Partial loss of mud circulation is almost certain to occur during drilling through these subnormally pressured sands; complete loss of mud returns is common when the sands are severely depleted. Consequently, several lost circulation- related problems have developed that have led to higher well costs. For example, on several occasions when partial losses occurred, the drill string became differentially stuck because of high differential pressure across the depleted sand. In other cases, the drill string became packed off and stuck because the open hole above the bit caved in. This occurred because of hydrostatic pressure loss when complete mud returns were lost.

Several well-known and accepted LCM blends and techniques have been used to combat lost circulation off the east coast.1-4 One successful but costly method was to set an intermediate-drilling-casing string to case off virgin-pressured sands before drilling through the depleted zones. The depleted zones were drilled at controlled rates of penetration (ROP's) with a mud containing a high concentration (15 to 20 lbm/bbl [43 to 57 kg/m3]) of LCM's. If this approach did not prevent lost circulation, one of two options was exercised. If tolerable partial mud returns were experienced, drilling was continued. If mud losses were intolerable, however, an LCM pill with a much higher concentration than in the active system was spotted in the open hole, and the formations were allowed to "heal" before drilling operations were resumed. This approach, however, was not optimum. Permanent formation damage occurred because of whole mud losses to the formations, the overall well cost increased, and the completion quality was compromised because it was limited to 5-in. [127-mm] cased-hole gravel packs. Consequently, a new preventive approach was sought to combat lost circulation.

We decided to develop an LCM blend, using commercially available products, that possessed wide ranges of particle sizes and types that could bridge against the formation as well as withstand high differential pressures. This paper documents the development and the successful use of such a blend. The sealing effectiveness has been tested successfully. In addition, the blend has been used as an integral part of a water-based drilling fluid for preventing lost circulation in subnormally pressured, unconsolidated sandstones off the east coast.

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