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.

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 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

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.

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.

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.