Hashim, H., Sarawak Shell Bhd. (Malaysia) Abstract A five well trial with Environmentally Acceptable Invert Oil Emulsion Mud (EA-IOEM) has been carried out in the Balingian area offshore Sarawak during 1985 and 1986. The trial was initiated after an unsatisfactory outcome of a field test programme with KCl/polymer muds. Two appraisal and three development wells with planned deviation angles ranging from 45 to 58 deg. were selected. The trial was carried out in the 12 1/4" and 8 1/2" hole sections. The objections of the trial were to eliminate drilling, evaluation and production problems caused by poor hole conditions which were experienced in high angle wells drilled with simple water based mud (WBM). A suitable base-oil for the trial was selected to meet the following three criteria: a high flash point, a low kinematic viscosity and a low toxicity. The experience gained in the field trial has been successfully applied to the Erb West infill drilling programme to solve the zonal isolation and drilling problems experienced in this area with WBM. The paper addresses the operational, petrophysical and geological aspects of the trial and includes recommendations on cost and consumption estimating. Introduction The Balingian Province consists of a number of fields (including Temana and D18) which are located off the coast of Sarawak in the South China Sea (Figure 1). Sarawak Shell Berhad (SSB) is the operator for these fields under a Production Sharing Contract with the Malaysian National Oil Company, Petrolian Nasional Berhad (PETRONAS). Poor hole conditions (severe washouts and erosion of the bore hole wall) cause a number of drilling, evaluation and production problems in the Balingham Province. These include: inadequate hole cleaning caused by irregular hole shape and local washouts, leading to low rate of penetration (ROP), tight hole and tripping problems; difficulties in getting logging tools to bottom; poor quality logs resulting in a reduction in the standard of log evaluation; difficulty in assessing cementation volumes resulting in excessive bottom hole pressures (due to long cement columns) and higher or lower than planned top of cement (TOC); poor mud displacement efficiency during cementing due to oversize hole, either locally or over the whole open hole resulting in channeling and consequent poor zonal isolation; later production problems such as early water/gas breakthrough due to flow behind casing. REASONS FOR EA-IOEM TRIAL Many of the wells drilled with conventional water based mud in SSB operations reach their objectives and are logged and completed without serious operational problems. Where problems relating to poor hole conditions occur these are usually, although not exclusively, in higher angle wells (generally above 50 deg. inclination). The first step in attempting to resolve such difficulties is to provide a better quality, near gauge hole. P. 58^

Abstract Several wells with bottom hole temperatures in excess of 400F have been drilled in South Australia. Two early wells were drilled with Lignite-Lignosulfonate fluids and two recent wells used a newly introduced high temperature polymer system. A brief comparison of these high temperature wells has been made. The effects of temperature on the performance and properties of the polymer system are examined and the need for further polymer system are examined and the need for further improvements in the area of high temperature drilling fluids is also considered. INTRODUCTION AND GEOLOGY The Cooper-Eromanga Basin in Australia comprises sediments ranging in age from Cretaceous to the Pre-Permian basement. From surface to the "Transition Pre-Permian basement. From surface to the "Transition Beds" at 5300 ft, the formations are mostly mud-making silts and clays. Below the transition zone, the formations are sandier in nature with interbeds of sand and silt and occasional coals. The boundary between the Cooper and Eromanga Basins is in the Early Jurassic-Upper Triassic period at 7200 to 7300 ft. The Cooper Basin is Permo-Triassic while the greater Eromanga Basin is Jurassic-Cretaceous. Temperature gradients in the area range from 1.7F/100 ft to 3.1F/100 ft, however most wells are less than 10,000 ft deep and thus the higher temperature ranges are not usually encountered. The four high temperature wells discussed have been drilled in the Moomba Block 2A of Petroleum Exploration Leases 5 and 6 in South Australia. A locality map is given in Figure 1. These hot wells have been drilled with several aims: As exploratory holes As part of the operator's accelerated gas development project Though the wells only have a temperature gradient of 2.8F/100 ft, they have been drilled deeper to 12,000 ft, at which point bottom hole temperatures of 400F have been approached. A general stratigraphic column of the wells is given in Table 1. CASE HISTORY NO. 1 The first well was drilled in 1971 to a depth of 11,974 ft and the bottom hole temperature at TD was 413F. Pressure gradients of up to 0.73 psi/ft were encountered. Drilling and mud data for this well are given in Table 2. Top Interval - 17 1/2" Hole: 0 to 1172 ft This interval was drilled with a Gel spud mud, but due to the presence of hard duracrust it took 4 days to reach casing point of 1172 ft. Difficulty was experienced in running in 13 3/8" casing, and it took 8 days to finally cement the casing in place. Intermediate Interval - 12 1/4" Hole: 1172 to 6211 ft This section was drilled with an 8 1/2" bit using Water-Native Clay mud through mud-making silts and clays into the "Transition Beds" at 5600 ft. The system was then mudded up to a Lignosulfonate fluid and drilling continued with a 9.7 ppg mud weight into the Toolachee Formation. At 8734 ft the mud weight had to be increased to 10.3 ppg to control gas within the coals and sands. Drilling was suspended at 8790 ft and the hole was opened to 12 1/4" to 6211 ft. 9 5/8" casing was then cemented in place. Production Interval - 8 1/2" Hole: 6211 to 11,974 ft Production Interval - 8 1/2" Hole: 6211 to 11,974 ft Drilling continued with a 10.0 ppg Lignosulfonate mud. The mud weight was slowly increased to 10.8 ppg at 9261 ft, up to which point apparently normal ppg at 9261 ft, up to which point apparently normal pressure gradients were encountered. When running pressure gradients were encountered. When running in for DST No. 5, part of the test assembly was lost, but was recovered on the first attempt with an overshot. Drilling continued to 10,107 ft when the weight had to be increased to 11.2 ppg to contain high pressured gas in the Epsilon Formation. An 80 barrel gas kick occurred which was finally killed by increasing the mud weight to 13.3 ppg. At 10,172 ft the mud weight had to be increased again to 14.6 ppg. DST No. 10 at 10,241 ft indicated a pressure ppg. DST No. 10 at 10,241 ft indicated a pressure gradient of 0.73 psi/ft and a bottom hole temperature of 360F. Additions of Lignite for high temperature fluid loss control were commenced with a Lignite : Lignosulfonate ratio of 1:1. 5% by volume of diesel oil was also added to improve the high temperature properties of the mud. Drilling continued to T.D. at 11,974 ft with a 14.6 - 14.8 ppg mud weight. ppg mud weight. Severe flocculation and dehydration occurred below 10,400 ft. Chemical treatment was not effective, necessitating large water dilutions which led to a high barite consumption to maintain mud weight. Logging was completed with difficulty and most tools did not reach bottom, probably due to downhole mud gelation. The well was then plugged and abandoned. A total of 12 DST tests and 4 cores were taken. The mud cost based on 1984 prices was $207,277 and the well took 107 drilling days and 127 total days. The maximum mud weight used was 14.8 ppg and the maximum flowline temperature encountered was 180F. The estimated bottom hole temperature was 413F. CASE HISTORY NO. 2 The second well was drilled in 1978 to a depth of 12,685 ft and bottom hole temperature at TD was estimated at 375F. The well was apparently normally pressured to 10,500 ft. A gradient of 0.65 psi/ft pressured to 10,500 ft. A gradient of 0.65 psi/ft was encountered at 10,718 ft and at 12,462 ft the gradient had increased to 0.73 psi/ft. Drilling and mud data for this well are given in Table 3. Top Interval - 17 1/2" Hole: 0 to 852 ft The well was spudded with a Gel-spud mud, and drilled to 832 ft. 13 3/8" casing was subsequently run and cemented. Intermediate Interval - 12 1/4" Hole: 852 to 6600 ft A Water-Native Clay mud was used to 3300 ft, and was then mudded up to a lightly dispersed Lignite- Lignosulfonate mud. Before reaching the Transition Zone, the mud weight was increased to 10.0 ppg with drilled solids. The viscosity ranged from 40-50 sec/qt. At 5266 ft drilling was halted for 7 days due to rig repairs. Drilling then continued and tight hole was encountered at 5600 ft which required extensive reaming to bottom. To combat hole wash-out, the viscosity was increased to 45-50 sec/qt to casing point of 6600 ft. After logging, 9 5/8" casing was run and cemented. Production Interval - 8 1/2" Hole: 6600 to 12,685 ft Production Interval - 8 1/2" Hole: 6600 to 12,685 ft Drilling continued with mud from the previous interval and properties were improved as drilling progressed. progressed.

Summary This paper highlights the major drilling problems encountered in the field development programmes offshore Malaysia from 1978 to mid-1983. The major problems identified were pipe sticking which was common in all the areas and top hole drilling problems encountered in a few fields offshore Sabah and Sarawak. problems encountered in a few fields offshore Sabah and Sarawak. Generally, the problems were related to drilling deviated wells through the soft and unconsolidated formations common in this region. Preventive measures employed by the Contractors hove been effective in overcoming these problems in the later years of the period under consideration. period under consideration Introduction Malaysia is currently producing all of its crude oil from her offshore oil fields located in three areas, i.e. offshore Te engganu, offshore Sarawak and offshore Sabah as shown in Figures 1, 2 and 3, respectively. EPMI (Esso Production Malaysic Inc.), which is the major operator in offshore Terengganu, drilled a total of 180 wells from 1978 to mid-1983. In addition, 6 wells were also drilled by EMPI in Tembungo field offshore Sabah. SSB (Sarawak Shell Berhad) and SSPC (Sabah Shell Petroleum Co.), on the other hand, are the major operators in offshore Sarawak and Sabah drilling 96 and 60 development wells respectively, for the some period. In offshore Terangganu, the formations are predominantly massive siltstones and claystones, which are highly reactive to water and interbedded with hard shale streaks ad coal stringers. The offshore Sarawak area is divided into four main geological provinces, i.e. the Baram Delta, Balingian, Central and South West provinces, i.e. the Baram Delta, Balingian, Central and South West Luconic. In the Baram Delta and Balangian provinces, the formation are mainly clastics where the main hydrocarbon accumulations are anticlinal and fault closures. The reservoirs in the Baram Delta are fluviomarine in nature, naturally depleted and are more continuous than those in the Balangian Province. The Central and the South West Luconic provinces are characterised by extensive carbonate build-up and the traps are overlain by clastics from seabed to about 1371.5 m (4500')-ss. The sediments in offshore Sabah area are mainly clastics and usually consist of alternating series of sand, silts and cloys. They are very soft and unconsolidated. Structurally, the area is very complex due to strong folding and faulting. P. 12–40 P. 12–40

Abstract Preformed stable foam is a proven process that has an extensive successful Preformed stable foam is a proven process that has an extensive successful track record. This paper emphasizes its use in several applications in low pressure reservoirs, such as: Sand cleanout, recompletion, new completions, pressure reservoirs, such as: Sand cleanout, recompletion, new completions, and concentric tubing work. New applications for stable foam; namely, gravel packing and balanced-pressure caring far insitu formation saturation, are discussed. The use and importance of a foam circulation computer model is illustrated. This model has proven to be extremely accurate and valuable as a planning tool in establishing the liquid/volume ratio and annular back pressure requirements for balanced pressure operations. Case histories and survey results are presented to illustrate the cost savings and production benefits of foam circulation. Introduction The preformed stable foam process development was started by Chevron U.S.A., Inc. several years ago to solve the problem of extreme loss of drilling fluid in the underpressured pay zones of shallow wells in the San Joaquin Valley of California. Since that time, the process has been improved, modified and adapted to many uses. Over 17 patents have been issued covering various uses of preformed stable foam. Licenses have been issued to over 35 service companies around the world to make the process available to Chevron and other operating companies. To date, over 35,000 foam lobs have been performed. Numerous papers have been published reporting on the use of preformed stable foam for drilling large diameter holes, drilling lost circulation intervals, speeding penetration rate, drilling permafrost and washing perforations. perforations. This paper will address the use of preformed stable foam in the completion interval of underpressured reservoirs. PREFORMED STABLE FOAM PROCESS PREFORMED STABLE FOAM PROCESS The preforming of the foam on the surface is of critical importance. We have found experimentally and in the field that preformed foams can withstand much more contamination from crude oil, salt waters, and salts than foams formed in the presence of these materials. p. 10–76 p. 10–76

Abstract This paper presents the Mobil Oil Indonesia experience associated with cementing the 9-5/8 inch casing through the abnormally pressured and water sensitive sand/shale Baong formation in the Arun field, North Sumatra. The paper will discuss how the cement slurries and cementing procedures for the 9-5/8 inch casing have been modified to overcome two major problems. The first being the inability to fully displace the cement due to swelling of sensitive shales, the second being severe annular flow after cementing. This paper will further examine the changes made to slurry design after the recent discovery that circulating temperatures during 9-5/8 inch cementing operations are considerably lower then predicted by the API schedules. Because of these low temperatures, the slurries used in the pest were greatly over retarded which contributed to the long and costly afterflow periods. periods Introduction The Arun gas field is located in Aceh Province, North Sumatra (Figure 1). The field was initially discovered in 1971 when the Pertominc-Mobil Arun a well was drilled. The field is now being developed by directional wells drilled from four clusters as shown in Figure 1. To date, c total of 29 producing wells and 8 gas injection wells have been drilled. producing wells and 8 gas injection wells have been drilled. This paper will concern itself with the cementing of the 9-5/8 inch casing in directional producing wells. These directional wells hove been responsible for the majority of the problems associated with cementing casing through the abnormally pressured and sensitive Baong sand/shale formation. During the early stage of development drilling, unsuccessful cement jobs resulted from the inability to fully displace the cement due to hole packing by sensitive shales in the Baong formation. This was remedied by packing by sensitive shales in the Baong formation. This was remedied by the addition potassium salt and synthetic cellulose to the cement slurry. Once it become possible to place a full column of cement to surface, it was discovered that the slurry would not control flow from the high pressure salt water sands in the Baong formation. Modifications to the slurry and the addition of an anti-migration additive have eliminated or significantly reduced the severity of the cement afterflow.

Abstract The success or failure of drilling and completing Geothermal Wells depends greatly on available cementing technology. This requires not only having the knowledge of temperature stable competent materials but also a complete understanding of hole preparation, casing running procedures, mud displacement, lost circulation and the mixing-placing of the cement slurry. Many steam fields ore located where the formation contains poorly consolidated sedimentary deposits, rubblized shales and fractured volcanic rock. These formations are fragile in that some upheaval may have occurred disrupting the structural stability, and with low reservoir pressures, make them prime candidates for lost circulation problems. Many of the geothermal wells have to be drilled through and/or into these fractured formations. Loss of drilling mud or any other fluid put into the hole usually occurs creating problems which are expensive-to eliminate. This paper offers methods which have proven successful in combating lost paper offers methods which have proven successful in combating lost circulation during the drilling and casing cementing operations on geothermal wells located in fields all over the world. COMBATING LOST CIRCULATION DURING DRILLING (1) When drilling a geothermal well, lost circulation is to be expected. It apparently occurs repeatedly and is difficult and expensive to combat. If the hole is being drilled with mud and the mud loss becomes too great, the normal procedure is to add lost circulation materials to the mud, and hope that full returns can be regained. Too often this is not the case and another method must be tried. Plugback cementing usually becomes the next method because it has been used Plugback cementing usually becomes the next method because it has been used to eliminate the problem. If cementing equipment is not already on location, a call has to be made requesting equipment and the proper materials for high temperatures and lost circulation conditions from a cementing service company. From the time they were first called until they arrive on location, several hours will have elapsed. The drill string will have to be round tripped to remove the bit and the cementing equipment made ready to mix and place the cement slurry in the hole. The cementing composition selected for this type of job is usually API Class "G" Cement containing 40% Silica Flour and Retarder designed to be drilled out in 12 – 16 hours. The cement slurry is mixed and displaced. Because it has not been possible to fill the hole, the displacement may be cut short to allow the cement slurry to "drift" into the zone of loss. The drillpipe is then raised to be sure it is above the cement to wait a few hours before trying to fill the hole. This should allow the cement slurry time to thicken and become resistant to flow when subjected to an increased hydrostatic head. p. 14–73 p. 14–73

Abstract This paper compliments the potential use of aerated fluid drilling in oil-gas operation of which the techniques in application was further extended to geothermal energy drilling. Compared with the use of conventional mud in both oil-gas and geothermal drilling operation, the benefits or aerated fluid cannot be denied. However, the developed utilization of blind drilling in geothermal operation in Luzon, Philippines were observed to be more beneficial. This paper highlights the incremental costs involved in using aerated fluid compared with blind drilling with water in geothermal operation within the 8 1/2" hole interval when total lost circulation zones are encountered. Introduction The use of aerated fluid drilling in geothermal operation were less beneficial compared to its application on oil-gas operation. One major factor is that the horizons of conditions in geothermal drilling where aerated fluid is utilized are distinct from oil-gas drilling. While potential benefits of reduced mud density by air injection were cited in studies and laboratory researches as early as 1955 to 1958, it was not until in 1982 through a paper on air drilling techniques that drilling companies in the Philippines considered the application of aerated fluid drilling on geothermal operation. Among the twenty-five (25) known geothermal reserve areas (KGRAs) in the Philippines, five (5) were developed into project areas. In April 1982, Philippines, five (5) were developed into project areas. In April 1982, the combined output of these five geothermal project areas totalled 556 megawatts. Three of these project areas located in Manito, Albay; Tongonan, Leyte and Palimpinon, Southern Negros were developed by PNOC Energy Development Corporation, a drilling operator subsidiary of the Philippine National Oil Company or PNOC. The other two project areas Philippine National Oil Company or PNOC. The other two project areas located in Makiling, Banahaw and Tiwi, Albay were developed by Philippine Geothermal, Inc or PGI Union Oil. It was in this two PGI project areas (refer to map) where aerated fluid/water drilling were implemented in well numbers "Bul-67", in Makiling, Banahaw and "Kap-25" in Tiwi, both within the geographical area of Luzon, Philippines. The drilling of these two wells were done by PNOC Energy Drilling, Inc as-the contractor. p. 14–81 p. 14–81

Abstract This paper briefly discusses the abnormally high temperature and pressure conditions in the Arun Gas Field and examines the special mud requirements caused by these extreme conditions. The next section focuses on the Liquid Mud Plant (LMP) which has been developed for use in the Arun Field to meet these special drilling fluid requirements. The paper's conclusion points out the particular benefits of the LMP which produce cost savings in terms of both time and materials. produce cost savings in terms of both time and materials Introduction A Liquid Mud Plant (LMP) has been developed in the Arun field since the first Arun development well was drilled in 1976. The Liquid Mud Plant was built for mixing, treating and storing expensive invert oil emulsion mud. The economic need to conserve and reuse this mud was realized early in the development phase of the Arun field. The invert oil emulsion mud is mainly used in the drilling of Arun wells below the 13-3/8" intermediate casing where abnormally high temperatures and high pressures are encountered. A diagram and explanation of the physical layout of this LMP is given in Figures 1 and 1A. Figure 2 shows the average static reservoir pressure and temperature curves for Arun wells. The Need For Invert Oil Emulsion Mud In the discovery and delineation drilling phase, wells were drilled using a lignosulfonate type mud to depths which varied from 11000' to 12000'. Most drilling problems were associated with the high temperature and high pressure shale and salt water sands which overlie the high pressure of the pressure shale and salt water sands which overlie the high pressure of the Arun limestone gas reservoir. In the last two delineation wells, an invert oil emulsion mud was used to drill through the Lower Keutapang, Baong and Arun formations. The Keutapang and Baong shales are also water sensitive. It was found through experience that the invert oil emulsion mud performed better than a lignosulfonate type mud. It required less treatment and eliminated many of the problems in drilling the lower Keutapang, Baong and Arun formations. As a result of this experience, invert oil emulsion mud is used in Arun development drilling when the well penetrates these formations. The Need For Two Types Of Invert Oil Emulsion Mud Two types of invert oil emulsion mud are used in the Arun wells. p. 14–39 p. 14–39

Drilling the 26 in. surface hole in the Tiwi Geothermal Field in the Philippines is characterized by low penetration rates and rough drilling Philippines is characterized by low penetration rates and rough drilling due to the presence of hard andesite boulders in the unconsolidated surface alluvium. This paper describes how drilling time and problems associated with rough drilling were reduced by using a downhole mud motor to power a stabilized 26 in. drilling assembly. Introduction The Tiwi Geothermal Field is located on the flanks of the extinct Malinao Volcano approximately two hundred and fifty miles southeast of Manila on the Island of Luzon in the Republic of the Philippines. Approximately 80 wells have been drilled in the Tiwi Field since exploratory work was begun in 1972 by Philippine Geothermal, Inc., a wholly owned subsidiary of the Union Oil Company of California. These geothermal wells range from 1000 ft. to 9000 ft. in depth, with the average well being about 5000 ft. deep. A typical casing program consists of 20 in. casing cemented in 26 in. hole at 300 ft., 13- program consists of 20 in. casing cemented in 26 in. hole at 300 ft., 13- 3/8 in. casing cemented in 17-½ in. hole at 1300 ft., and 9-5/8 in. casing cemented in 12-¼ in. hole at 3000 ft. An 8-½ in. hole is drilled through the producing reservoir and 7 in. perforated liner is set from the 9 5/8 in. casing shoe to the well perforated liner is set from the 9 5/8 in. casing shoe to the well TD as shown in Fig. 1. The top 300 ft. of formation consists of unconsolidated surface volcanics and alluvium containing large andesite boulders up to 10 ft. in diameter and other volcanic debris from past eruptions. The extreme size of these boulders was proven during the excavation for the first power plant built in Tiwi. The underlying formation to 1300 ft. is altered to fresh andesite with streaks of clay. It is the upper sections of hole, especially the unconsolidated surface volcanics, where we found a down-hole mud motor extremely useful. In the first wells, the 26 in. hole was completed by first drilling a 17- ½ in. pilot hole and opening it to a 26 in. hole. This method was very time consuming because of low penetration rates and very damaging to drilling equipment due to high torque encountered in drilling and opening unconsolidated formation. With the development of a 12 in. downhole mud motor, we are now able to drill a 26 in. hole using a stabilized bottom-hole assembly so that hole-opening and reaming are no longer required. By using an assembly consisting of 26 in. tungsten-carbide (TCI) bit, a 25-15/16 in. integral-blade nearbit stabilizer, a 12 in. mud motor, a 26 in. roller reamer and 10 in. drill collars, we have reduced rotating time in the 26 in. hole from 88 hours to 22 hours. Downtime due to rough drilling conditions has been reduced by almost 100 percent. Original Drilling Procedure In the Tiwi Geothermal Field, a 30 in. conductor is cemented in a hole dug with a backhoe to 15 ft. below ground level. A 26 in. hole is drilled to 300 ft. and 20 in. casing is cemented to consolidate sloughing hole, seal off surface water, and isolate the sometimes massive lost circulation zones associated with the unconsolidated surface rubble. The extremely hard andesite boulder are sometimes encountered as soon as drilling out of the conductor pipe. Since only milled tooth bits were available in the 26 in. size at the beginning of the project, penetration rates would be as low as a few inches per hour while trying to drill through these boulders. In order to use available TCI bits, a 17-½ in. pilot hole was drilled to 300 ft. and then opened to 26 in. diameter. Even with the TCI bits, penetration rates were very low due to lack of adequate bit weight penetration rates were very low due to lack of adequate bit weight when drilling close to surface. An additional problem was downtime due to the rough drilling conditions. Even with the use of multiple shock subs in the drill string, extreme vibration and bouncing caused by drilling the boulders would literally shake the drilling rig apart as nuts and bolts would fall from the derrick. The drill string not only suffered from the high impact forces due to the bouncing, but was also subject to many torsional failures as sloughing rocks would intermittently wedge the bottom-hole assembly. Rotary chains were constantly breaking and rotary tables suffered an unusually high rate of damage from the high torque. Under these conditions an average of 88 rotating hours was needed to drill and open the 26 in. hole. First Use Of The Mud Motor It was felt that a downhole mud motor with its high bit rpm would solve the problem of low penetration rates in the near surface section of the hole where there was inadequate weight on the bit to drill the hard andesite boulders. Using a 17-½ in. TCI bit on a 9-5/8 in. mud motor, the 17-½in. hole was drilled to 300 ft. with penetration rates increasing from 6 fph with the conventional assembly to 18 fph with the mud motor. The hole still needed to be opened to 26 in., slowing the combined penetration rate to 4 fph, an increase of 1 fph over the conventional rotating method. When a 26 in. milled tooth bit was used on the mud motor, the bit wore out so quickly it was not successful when drilling the andesite boulders. In 1977, in cooperation with service companies, a 26 in. TCI bit was designed and manufactured for use on the downhole mud motor in drilling the very hard formations. The 26 in. TCI bit was used on a 9-5/8 in. mud motor to drill the 26 in. hole in Tiwi with exceptional results. Rotating time for the top 300 ft. of hole was reduced from an average of 88 hours to an average of 34 hours with the 9-5/8 in. mud motor on a 26 in. TCI bit. Additional Problems Using The Downhole Mud Motor Although using the downhole mud motor had improved the drilling of the surface 300 ft. significantly, there were still problems with the system. problems with the system.

Where severe drilling conditions exist, especially the combination of water-sensitive sloughing shales, abnormal formation pressures and high bottom-hole temperatures, several operators in South East Asia regularly use "invert emulsion" oil muds to drill and complete trouble-free gauge holes. This paper will review oil mud operations in the South-East Asian region, and a case history will be presented to illustrate the successful use of oil mud in the development of a major Indonesian gas field. Some misconceptions still surround the use of oil muds. Modern oil muds are stable, practical and relatively simple drilling fluids which may be scientifically formulated to match the most severe drilling conditions. This paper will attempt to clarify some of the misunderstandings commonly associated with oil muds. The range of application and advantages of an oil mud will be demonstrated, and the physical and chemical properties of a typical invert emulsion oil mud will be discussed. Finally, the key to an efficient oil mud program stage. Using examples from one Indonesian operator's extensive experience, the various economic and logistic factors to be considered when using oil mud will be discussed. Oil Mud Country South-East Asia is one of the world's more difficult drilling areas. High geothermal gradients occur throughout the region and geopressured, water-sensitive shales are often present. Drilling problems typically include swelling shales, tight hole, bridging and problems typically include swelling shales, tight hole, bridging and stuck pipe. High mud densities are often required, and several areas posses hydrocarbon reservoirs containing water-sensitive clays. posses hydrocarbon reservoirs containing water-sensitive clays. Through inhibitive salt-polymer mud systems are becoming more popular, the only fluid capable of overcoming all these drilling popular, the only fluid capable of overcoming all these drilling problems is oil mud. problems is oil mud. In most cases, operators in South-east Asia use oil mud for two reasons: A well cannot be drilled to total depth with a water base mud. To reduce overall well costs. In Indonesia, oil mud is used regularly to drill geopressured, water-sensitive shales in North Sumatra and Kutei Basins, and has also been used for shales control in the East Java (Mudura), North West Jave (Sunda). Central Sumatra and West Natuna Basins (Figure 1). The Kutei Basin also contains deep shaly-sand reservoirs which are susceptible to damage by filtrate invasion from water base drilling and completion fluids. One well in the Sunda Straits between Java and Sumatra used oil mud to drill underbalanced through geopressured shales with interbedded fracture zones of volcanic ash. Oil mud has also been successfully used to control sloughing shale in the Malay Basin of West Malaysia, the Sarawak Basin of Brunei and East Malaysia and The East Palawan Basin of the Philippines. Oil mud packer fluids have also been used successfully on production wells in Indonesia. Brunei and Malaysia. Advantages Of Oil Mud Oil muds have many advantages over water base drilling and completion fluids, and may be used to: Prevent damage to water-sensitive reservoirs Control water-sensitive shales Resist high bottom-hole temperatures Drill gauge hole Control salt sections Allow underbalanced drilling in shale Extend bit life Improve drill string lubrication, i.e. reduce rotating torque and minimize wall-sticking tendencies Eliminate corrosion of drillstring and tubulars These benefits are over and above the regular functions of a water base fluid, e.g. cuttings removal, control of formation pressure and bit cooling. Shale Control The most important feature of oil mud is its ability to prevent swelling of water-sensitive clays and shales. All water base muds water as the primary or "continuous" phase, so no matter how high the mud salinity or how low the phase, so no matter how high the mud salinity or how low the filtrate loss, some water will always come into contact with the borehole wall when water base muds are used. If the formation exposed to the well bore contains clay or shale, then these will tend to absorb water into the clay structure to compensate for the water squeezed out during compaction. This effect is termed surface hydration. The force exerted by the shale to re-absorb the water lost during compaction is termed the surface hydration force. This force occurs when a borehole is drilled into a shale formation and the confining stress due to the weight of the overburden is relieved. This surface hydration force exists for all shales below a few thousand feet and its magnitude is approximately equal to the "vertical matrix stress" of the formation. Using data from the U.S. Gulf Coast, the matrix stress is found to have an approximate value of 0.535 psi/foot in normally compacted shales, and value somewhat less than this in geopressured shales. Table 1 lists shale surface hydration force versus depth for normally compacted shales. All shales exhibit this force, and all water base muds will give some of their water to the shales. Encapsulating polymers may be added to a water base mud to provide a polymer film over shales exposed to the borehole.

Annular gas flow following cement has been a problem in many areas throughout South-East Asia. In some offshore fields, gas migration occurs on surface, intermediate and production casings and liners. This phenomenon gives rise to gas pressure on the annulus between casings or phenomenon gives rise to gas pressure on the annulus between casings or even interzone communications. Both can cause costly remedial repair work and unpredicted high volume flow to the surface has on occasions caused catastrophic disasters. Laboratory testing and field applications in many areas of the world have shown compressible cement slurries to possibly be the most effective means of helping to prevent annular gas flow developed thus far. This paper will review the development and application of compressible cement slurries. Over 800 compressible cement slurry applications have been run throughout the world and the success ratio is greater than 90%. Applying this technique on a more wide-spread basis may possibly reduce the many problems associated with annular gas flow in South-East Asia. Introduction Initial application of compressible cement slurries in South-East Asia has been confined to offshore Bomeo. Here, annular gas flow has been encountered on surface and intermediate casing. Some wells have gas flow back to surface within ½ to 1-½ hours after the primary cementing job has been completed. This occurs on casings which are cemented back to surface as well as those where cement is only brought back just into the last cemented casing. In this particular area, weak formations with natural fractures extend irregularly to a significant depth below the sea bed. Lost circulation is a common occurrence even at the minimum mud density required to control the gas pressure. When annular gas flow is not controlled, lost circulation and interzone gas migration into the fractured zone apparently can result in gas percolation from the gas zone to the ocean floor some distance from the well bore even with no gas flow from the conductor pipe-surface pipe anulus. Conventional techniques for improving mud displacement, fluid loss control and cement bonding have met with very limited success. Annular gas flow may still occur and, at the least, monitoring and disposal of the gas at the surface is required. Annular Gas Annular gas flow can occur in two distinct forms within a wellbore: interzone communication; and direct gas flow to the surface. Both systems waste valuable natural resource, are dangerous and are costly to repair. Up until recently well operators have been more or less unsuccessful in solving the problem of annular gas flow. Early studies using a large scale laboratory model evaluated different drilling fluids, spacers, flushes and cementing compositions with respect to density, viscosity and flow characteristics. Fluid loss, pipe configurations, and mud displacement were stated as factors which should be given attention. These studies demonstrated more consideration should be given to the planning of primary cementing operations in a gas well. To help control annular gas migration, a positive hydrostatic pressure greater than the gas formation pressure must be maintained. Incompleted drilling fluid displacement can create a channel through which formation gas can migrate. The problems of annular gas flow cannot be minimized unless the mud displacement efficiency of the cement is high. A later study indicated cement slurries without fluid loss control may fail to transmit full hydrostatic pressure should a restriction or bridge occur as a result of water loss from the cement slurry into a permeable sector. This would allow the pressure below the restriction to fall below the gas zone pressure and result in gas entry into the wellbore. By minimizing the fluid loss of the cement slurry, some annular gas flow problems were eliminated. Further research evaluated the influence of common slurry properties and miscellaneous techniques. These included applying surface pressure, increasing the slurry and/or increasing the mud density to increase the initial hydrostatic pressure; using multiple stage cementing to decrease the height of the cement column (for mostly intuitive reasons); adjusting the thickening time in an attempt to decrease transition time; eliminating free water on the theory annular gas flow was promoted by free water channels; increasing the mixing water density in an attempt to maintain annular pressure through the permeability of the partially set of gelled cement column. To this point, both research and field experience showed nearly all good cementing practices had on occasions been credited for helping control annular gas flow. However, no single method existed which was consistently successful for controlling annular gas flow. An extensive research program performed by Tinsley et al, developed a method which proved very effective in preventing or minimizing annular gas flow where other methods have failed. Briefly, this new method used a compressible cement slurry to provide a means of effective annular pressure maintenance. A cement slurry, before hydration begins, behaves like a true fluid in that it can transmit hydrostatic pressure based on fluid density and depth. In the early stages of the hydration process, a cement slurry begins to develop measurable static gel strength and, under certain conditions, loses its ability to transmit pressure. When this stage occurs, the slurry is neither a liquid nor a solid, but a plastic-like mass of weekly associated particles containing water in the pore spaces. However, prior to reaching particles containing water in the pore spaces. However, prior to reaching this stage, the initial hydrostatic pressure is equal to the summation of the annular fluid gradients times the vertical intervals covered. As static gel strength develops, a reduction in the volume of water within the pore structure of the cement results in a pressure decrease. pore structure of the cement results in a pressure decrease. Two mechanisms cause this volume decrease. First, even with the best fluid loss control additive, the fluid leak-off rate is still significant and filtrate may be lost to permeable formations.

A good solids control program is essential in order to attain the goal of an optimized drilling program. Proper application and utilization of mechanical solids removal equipment enables the driller to maintain the desired drilling fluid properties which in turn makes it possible for the drilling operation to be carried out in an efficient and possible for the drilling operation to be carried out in an efficient and economical manner. Drilled solids have a direct and pronounced effect on the drilling fluid. Since the drilling fluid is itself so closely related to a wide range of factors which determine both daily and total drilling costs, it is obvious that there exists a strong relationship between the control of drilled solids and the control of drilling costs. This paper will present methods to calculate the mechanical efficiency of solids control equipment on site during drilling operations and will demonstrate from case histories a method of determining the economic justification for the use of mechanical equipment. Data presented in this Paper is based on information gained in the field evaluation of various types of solids control equipment, including sophisticated fluids processing systems, under a wide variety of weather, geographic and geologic conditions. Introduction The drilling industry as we know it today has evolved through a combination of trial-and-error and technology, of hard work and luck. Through more than a century of development many of the problems encountered by the pioneers in the business have been problems encountered by the pioneers in the business have been solved, or at least made bearable. The technological advances of the drilling industry are on a par with those of virtually any other industry. But there is one serious problem still facing us and it has been a problem since the earliest days. Very simply, that problem is how to get the dirt out of the hole. The removal of drilled solids from drilling fluid, or drilling mud, has been a problem since the introduction of rotary drilling rigs, The early day driller used gravity settling to accomplish solids removal, and earthen pits were a standard part of the drilling site. Drilling mud became more complex, however, part of the drilling site. Drilling mud became more complex, however, and with the use of barite as a weighting agent in the early 1930's the need for better methods of solids removal became apparent. Vibrating screens designed to remove the undesirable drilled solids while salvaging the barite and liquid mud were introduced to the drilling industry. These "shale shakers", as they came to be called, were the first attempt by the drilling industry to use mechanical equipment for more effective and economical solids removal. During the past half-entry there have been numerous types of solids removal equipment developed and tried in the industry. When judged solely on an engineering evaluation, much of the equipment was found to be satisfactory for applications in the drilling industry. Nevertheless, the equipment was not widely accepted until economics dictated a reassessment of our drilling practices. Solids removal equipment which had been judged to be too costly and too bothersome during an earlier era of relatively inexpensive drilling and minimum regulation is now being seriously considered as a means of reducing total drilling costs and complying with new environmental regulations. Drilling Fluids Drilling fluid, whether it be water-base or oil-base mud, can be described simplistically as being a suspension of solids in a liquid medium - - . Liquid Phase. This may be either water, oil or salt solution. . Solids. These may be described as either additives or contaminants. The additive materials are further differentiated on the basis of their specific gravity. High gravity solids, such as barite, have a specific gravity of 4.2 or more and are used to increase the density of the drilling fluid. Low gravity solids, such as bentonite. have a specific gravity of 2.6 and are used as a viscosifying agent. Drilled solids, also have a specific gravity of 2.6. and are also referred to as low gravity solids. Drilled solids are the most common contaminant found in drilling fluids and they are responsible for the majority of problems associated with drilling fluids. These drilled solids, by their sheer volume, can significantly alter the density of a fluid and both the volume and the size of the drilled solids can drastically affect the viscosity of the drilling fluid. Over the years, drilling fluids have been developed to the point that they do an excellent job of transporting drill cuttings up the bore and to the surface. However only part of the job has been done when drilled solids reach the surface. At this point the problem becomes that of removing the drilled solids from the drilling fluid. In as much as the volume and type of solids in a drilling fluid directly influence the density and viscosity - - and indeed all the rheological properties of the drilling fluid, it obviously follows that drilled solids greatly influence mud costs, well costs, rates of penetration, hydraulics, possibilities of kicks" and or returns, and an penetration, hydraulics, possibilities of kicks" and or returns, and an almost endless list of both small and large drilling problems. From both an engineering and an economic viewpoint, solids control becomes one of the most important aspects of drilling fluid treatment. It has been estimated that more money is spent annually to control drilled solids and to correct problems created by inadequate solids control measures than is spent on all problems created by inadequate solids control measures than is spent on all other problems encountered in drilling operations.

Drilling Technology has been continuously faced with new problems in drilling deeper and more difficult holes. A major problem is excessive friction caused by unstable hole conditions which in turn are due to sensitive clay formations or poor drilling practices. In addition to improvement by mechanical means and sophisticated tools, the drilling fluid properties are of utmost importance in drilling such holes successfully to final depth. Two important drilling fluid properties in this respect are lubricity and clay inhibition. Lubrication can be obtained by adding liquid and solid lubricants to the circulating fluid, and thus greatly reduce torque, over-pull and casing wear. The inhibitive properties of the fluid may reduce or prevent swelling of clay and restrict the tendency of the clay to adhere to bit and stabilizers, the "balling up". Clay preservation, moreover, prevents undue damage to the formation permeability in the pay zone. In order to keep the drilling fluid in permeability in the pay zone. In order to keep the drilling fluid in good shape it should be reasonably resistant to high temperatures and contaminants; drilled solids have to be removed continuously. Drilling fluid properties have to be monitored continuously and immediate action has to be taken if sudden changes occur; automation of drilling fluid control is progressing fast. The presentation reviews some recent developments in drilling fluid technology which greatly contributed to reducing friction. Some case histories are given of successful applications. Introduction Excessive friction in an uncased hole is often caused by unstable hole conditions. When drilling a hole into the formation, the existing mechanical stress conditions are disturbed resulting in serious instability of the wall which may eventually lead to total collapse. Plastic shales or rock salt may even "flow" into the hole Plastic shales or rock salt may even "flow" into the hole after the bit has passed, particularly when drilling too fast. Clays may swell by hydration with the same effect. In permeable sands, particularly in depleted zones, differential pressure sticking could cause stuck pipe. Balling of the bit and reamers in sticky clay formations is not only a nuisance because of the poor on pulling because of the piston effect of the balled bottom assembly. Such problems are far more serious in deviated holes, when the pipe lies against the wall or is even into it when drilling below key-seat or dog-leg. Casing wear is another hazard leading to costly remedial measures, particularly in deviated holes. Such difficulties can be partly prevented by good drilling practices, such as proper selection of the assembly weight on the bit, rotary and tripping speed, casing schedule and whatever other mechanical measures are available. It is generally agreed that the drilling fluid could play a major role in preventing drilling problems as described. DRILLING FLUID REQUIREMENTS Part of good drilling practice is optimum drilling fluid Part of good drilling practice is optimum drilling fluid characteristics. Mud weight should not be higher than necessary to keep formation pressure under control, as higher mud weight reduces the rate of penetration and may lead to circulation losses or worse. Fluid viscosity has to be controlled when drilled clay is disintegrated and quickly increases clay content or when brine influx occurs, in order to maintain optimum hydraulics in the pumps and at bit nozzles. The filtrate loss should be low enough to prevent excessive cake thickness and to reduce the chances of differential pressure sticking. At times the mud should have formation pressure sticking. At times the mud should have formation preserving properties to limit mud making or clay swelling. preserving properties to limit mud making or clay swelling. Drilling fluids should exhibit good lubricity, both in the casing and open hole, in particular when deviating. What was considered to be an excellent mud some decades ago, will not suffice today or in future.

In less than one decade the production of crude oil in Indonesia has increased from less than 0.5 million to 1.5 million bbls/day. Natural gas production is still in its infancy, but recent discoveries show an production is still in its infancy, but recent discoveries show an extremely high potential. These achievements reflect a total revitalization of one of the world's oldest producing areas. They can be attributed for the most part to a healthy atmosphere created by a unique production sharing concept, a high success ratio in exploratory production sharing concept, a high success ratio in exploratory drilling aided by technological advances, a high potential in vast unexplored areas, and a concerted, yet co-operative, effort towards Indonesianization of the industry. Twelve years after the drilling of the world's first oil well, the search for oil began in Indonesia. By 1940 Indonesia ranked fifth among world producers. Then came World War II and the struggle for independence. Production, although increasing during this period, did not keep pace with world developments, and Indonesia dropped to twelfth place. place. In the last decade alone crude oil production has increased from less than 0.5 million to 1.5 million bbls/day. Natural gas production is still in its infancy, but recent discoveries show an extremely high potential. These achievements reflect a total revitalization of the nation's petroleum industry. They can be attributed for the most part to a healthy atmosphere created by a unique production sharing concept, a high success ratio in exploratory drilling aided by technological advances, a high potential in vast unexplored areas, and a concerted, yet co-operative, effort towards Indonesianization of the industry. This sudden expansion is playing a major role in the economic development of Indonesia as well as the rest of South East Asia. Self-sufficiency in energy is an important factor to any nation in a world that runs on petroleum. It does not come easy. It requires reserves, a market, capital, technology, and qualified manpower. Indonesia is generally credited with having approximately 2% of the world's proven reserves. Huge industrial developments in Japan, the United States, and South East Asia provide a natural market. However, when two national oil companies were merged to form Pertamina in 1969, there was little available capital and the industry had been run almost exclusively by a few foreign concerns. Indonesia had an immediate need. The solution came from the emphasis on a unique production sharing concept that was originated in 1961. Production sharing is allowing for the most rapid development Production sharing is allowing for the most rapid development of Indonesia's oil and gas industry. It is based on a division of actual production between foreign oil companies and Pertamina, rather than on the traditional division of net Pertamina, rather than on the traditional division of net profit. As a result, more emphasis is placed on reserves being profit. As a result, more emphasis is placed on reserves being a resource of the nation. Although the rules can be interpreted by some as being strict, the concept provides foreign contractors with an attractive opportunity for profitable operation in a world intent on total nationalization. To date, more than 52 production sharing agreements involving 35 foreign contractors have been written. The co-authorship of this paper is indicative of the atmosphere of co-operation existing between Pertamina and outside investors. The unitization agreement negotiated in 1970 among Japex, Union Oil Company of California and Pertamina for the development of the Attaka field is an example of the work ability of production sharing. Located in offshore Eastern Kalimantan, Attaka is the largest offshore oil field in Austral-Asia. The Attaka unit covers 112 square miles of contract area in a roughly rectangular block about eight miles south of the equator in the Makassar Strait. This agreement was instrumental in preventing unnecessary and costly wells from being drilled, permitted pressure maintenance and secondary recovery practices to be implemented, and allowed wells to be spaced according to the best engineering practices without regard to boundary lines. It was the first of many multi-national contracts that presently produce most of Indonesia's oil. Caltex's Minas field in Central Sumatra is well known as being one of the 25 fields in the world to have surpassed the billion barrel milestone, while on Irian Jaya 70,000 bbls/ day are being produced under an agreement hardly five years old. This operation by Trend in Irian Jaya involved only two medium-sized drilling rigs. In offshore Java, Arco's Arjuna field and IIAPCO's Cinta field produce 100,000 and 56,000 bbls/day respectively. As effective as the production sharing concept is, not all major production can be attributed to the arrangement.

Planning the drilling fluids program is one of the most important steps in Planning the drilling fluids program is one of the most important steps in preparation for the drilling of a welt Many factors influence the type and preparation for the drilling of a welt Many factors influence the type and properties of the fluid required. properties of the fluid required. This paper will outline some of the drilling problems that may be encountered in Southeast Asia; brief methods of anticipating these problems before they occur are developed. Techniques for dealing with various drilling problems through engineered drilling fluids program are discussed. In particular, the application of controlled salinity oil muds and the use of salt polymer mud systems for improved borehole stability, solids control, corrosion reduction, safety and economy, are emphasized. Current trends and developments in drilling fluids systems are discussed. Planning the drilling fluids program in Southeast Asia is Planning the drilling fluids program in Southeast Asia is similar to the same task any place in the world. The conditions one can expect to encounter vary from no-problem normal pressure situations to the impractical-to-drill high pressure, high temperature, completely unstable borehole pressure, high temperature, completely unstable borehole conditions such as reported by Ferti, Blake and Gray. 2 and 3. It is a commonly accepted estimate that more than 80% of the exploration wells drilled in Southeast Asia do encounter severe hole problems, resulting in the loss of valuable data and time, and preventing proper evaluation of a prospect. The loss of a hole is not uncommon. Historically, drilling fluid development saw improvements in controlling drilling fluid properties with little regard to effect on drilling. Causes of borehole problems were not understood and cures were often worse than the ailment. A better understanding of the basic causes of hole instability has led to new approaches being taken to eliminate or reduce problems. problems. There has also been a tendency in the past and even today to base the choice of mud system on only one to two criteria, such as low cost, availability, or ease of running, rather than on a scientific evaluation of all facets involved. In many cases the lowest cost drilling fluid system may not yield the lowest cost well drilled. If cost, environmental factors, and geological information were of no consequence, problem wells could be drilled with invert emulsion muds. This is not the case. A drilling fluids program must be designed to give maximum information, program must be designed to give maximum information, along with maximum hole stability at the lowest cost possible. This can only be attained if all factors are considered and the drilling fluid designed accordingly. The First Step The first step in planning any drilling fluids program is to gather all available data, such as geological seismic, and offset well information, to determine what conditions may be encountered in penetrating the section. With this information, decide what the specific problems are for the area and location in question. Consider briefly the depth of interest, lithology, pressures, temperatures, logistics, drilling equipment available, and qualifications of supervisory personnel assigned. personnel assigned. Choose the best drilling fluid type available for each phase of the hole programmed based on engineering and economic studies and considering the hazards of drilling expected, the cost of time lost due to unstable hole, availability of materials, and expertise to formulate and maintain the fluid. Divide the program into phases by drilled hole size, indicating the expected problems, the fluid properties range required, and the material concentration range estimated for each unit volume of drilling fluid consumed. Estimate the material requirements for each phase based on maximum consumptions, planning ample contingencies to cover any logistic problems or unpredictable hole conditions. Cost estimates and shipping tonnage/volumes for the well's total material requirements should be calculated. In an effort to expand on a method of planning the drilling fluids program by scientific, logical steps the following considerations are put forward. Origins of Unstable Borehole Conditions: i.e. Pressure Force Balance When a wellbore penetrates a sedimentary section it interrupts a process of physical and chemical change which has been going on for considerable time. Being penetrated by a drilling bit comes as something of a shock to these formations. The drilling process relieves pressure on the rocks at the borehole and the drilling fluid exposes them to an alien chemical environment. The average geologic section through which most wells are drilled consists of mainly shale, with sands and sometimes limestone or coal. Most drilling problems are derived from the shales. These are basically unstable rocks, composed of clay minerals which are compressible and water degradable. With depth of burial and increased temperature the clay minerals present at the surface are subject to alteration.