Mud System Research Articles

Rheological properties of biopolymers drilling fluids

Drilling muds are complex fluids, generally used to clean the well, maintain hole integrity, transport the rock cuttings, lubricate the drill bit and control formation pressures. Two basic types of drilling fluids are used, water based muds (WBM) and oil based muds (OBM). OBM are very effective but polluting, and environmental regulations continue to restrict the use of oil based muds in many areas of the world. In order to reduce the mud toxicity, we developed water based mud systems using two biopolymers, which are xanthan gum and scleroglucan, generally proposed for high permeability reservoirs or for complex geometries such as horizontal wells. In this study, we evaluated the rheological behaviour of different samples and we determined the effect of components such as clay, calcium carbonate and potassium chloride. This formulations exhibit non-Newtonian rheological behaviour which can be described well by the tree parameter in Herschel–Bulkley rheological model.

Effect of drilling fluids on coal permeability: Impact on horizontal wellbore stability

The objective of this study was to evaluate a series of mud systems and additives typically used in coalbed methane drilling in terms of formation of an instantaneous filter cake, ability of the coal reservoir to rid itself of the filter cake during production, and overall impact on coal permeability. To achieve this, a series of laboratory tests were conducted initially using artificially cleated gypstone rock (to simulate coal). This was followed by the use of large-diameter coal cores, which, unfortunately, did not allow for the tests to be done under in-situ confining stress conditions. The three mud systems tested against coal (Xantham Gum, HEC and Na-CMC) did not have a negative impact on coal permeability, in contrast to previous laboratory data that showed large decreases. Two fluid loss control additives, which have been used successfully in drilling clastic and carbonate rocks, were also tested using a non-ionic polymer mud system. During simulated drilling, these additives (FLC 2000™ and Q-Stop) were very effective in building a thin filter cake on the coal surface almost instantaneously, to the point that no solids were detected in the downstream fluid accumulator. During simulated production, a small pressure drop was sufficient to remove the filter cake. Coal permeability (to water) returned to its original (pre-test) value, which suggested that there was no permanent permeability damage caused by the two additives. When coal-derived fines were added to the drilling mud in another experiment using the same coal, the near wellbore coal permeability was reduced by 87.5%, indicating severe damage to the cleat system and in agreement with previously reported laboratory data. Following the very good performance of FLC 2000™ and Q-Stop in the laboratory tests, these two additives were then used in field applications. Their presence in the drilling fluid resulted in the successful drilling of 953 m and 1400 m of total horizontal length in the deep Mannville coals in Alberta (at True Vertical Depth of 1400 m and 1150 m, respectively). No borehole instability problems were encountered during drilling of the two horizontal wellbores. The monitored mud losses were low in both cases, with the horizontal well #2 experiencing lower mud loss possibly as a result of the absence of large fractures encountered along the horizontal path. Horizontal well #1 remained stable, which allowed sufficient time to insert a production liner.

Application of DSC for Emulsified System Characterization

This paper will describe how Differential Scanning Calorimetry (DSC) may be used to characterize emulsions, especially the concentrated and opaque water-in-oil emulsions encountered in the oil industry. After a presentation of the technique, we will point out how it is possible, from a single test performed on an emulsion sample without dilution, to get information about the solidification and melting properties of these complex fluids, the emulsion type, the amount of water, the presence of solute, the stability and even the droplet size. Some examples of applications are given concerning oilfield emulsions and oil-based mud systems.

A study on the solid-liquid 2 phase helical flow in an inclined annulus

An investigation is conducted to understand hydraulic transport characteristics of a solid-liquid mixture flowing vertically upward. Namely, this is the instance that solid particles are carried by non-Newtonian fluids in a slim hole concentric annulus with rotating inner cylinder. In this study a clear acrylic pipe was used in order to observe the movement of solid particles. The bulk axial velocities varied from 0.4 m/s to 1.2 m/s. The mud systems which were utilized included aqueous solution of sodium carboxymethyl cellulose (0.2∼0.4%CMC) and 5% bentonite solutions. Solid volumetric concentration and pressure drops were measured for the various parameters such as inclined annulus, flow rate, and rotational speed of inner cylinder. For both CMC and bentonite solutions, the higher the concentration of the solid particles are, the larger the pressure drops become.

Surface Albedo and Soil Heat Flux Changes Following Drilling Mud Application to a Semiarid, Mixed‐Grass Prairie

Drilling mud systems are used by the petroleum industry to facilitate and expedite the drilling of oil and natural gas wells. In western Canada, spent water‐based muds (WBM) are often applied to cropland and native prairie at low application rates as a disposal option. We speculate that application of drilling waste on native prairie in semiarid climates will alter the soil surface energy balance and adversely affect soil biophysical processes and subsequently ecosystem productivity. This study was initiated to examine the effect of application rate (0, 40, and 80 m3 ha−1) of summer‐applied WBM on surface albedo (α), soil temperature, and soil heat flux at the 0.05‐m depth (G0.05) and at the surface (G) over 42 d following application. Our results provide evidence of a significant alteration of these micrometeorological parameters with WBM application. Surface albedo decreased by 15% (relative to the control) with the application of 40 m3 ha−1 mud and by an additional 3% when this mud rate was doubled. The lower α meant that a greater proportion of incoming shortwave solar radiation (Rsi) was available for partitioning into components of the surface energy balance, including G This coincides with observed increases in G0.05, G, and soil temperature at the 0.025‐m depth, with higher WBM. By modifying heat flow and temperature in the root zone, WBM application may alter critical ecosystem biophysical and physiological processes, with important implications for overall biological productivity. The direction and magnitude of such changes, in conjunction with all the other ecological effects of WBM, will ultimately define the sustainability of the practice in this fragile ecosystem.

Effects of drill cuttings on biogeochemical fluxes and macrobenthos of marine sediments

Experimental work was performed on drill cuttings sampled from off-shore drilling operations. The cuttings contained remnants of two different types of drilling muds: a water-ilmenite based mud and an olefin-barite based mud. In a pilot experiment, a gradient of up to 65 mm thick layers of water-ilmenite based cuttings were added to 78 cm 2 core samples. In another set-up, 3 mm layers of water-ilmenite and olefin-barite based cuttings were added to replicate 1000 cm 2 box-core samples with natural benthic communities transferred from the Oslofjord, S.E. Norway. Boxes with no addition and addition of 3 mm “clean” sediment were used for control. Increased consumption of oxygen and nitrate indicated the presence of degradable organic phases in both mud systems. The release of silicate showed a general decrease with increasing thickness of the cuttings layer, but maximum rates in the 3.1 mm treatment indicated increased bioturbation at low and moderate doses. The initial (field) composition of the macrobenthic communities was maintained throughout the 3 months experimental period, and at community level, no significant difference was observed between the four treatments at the end of the exposure period. However, after grouping the treatments into “clean” (untreated control and 3 mm clean sediment) and “cuttings” (3 mm water-ilmenite and 3 mm olefin-barite based cuttings), multivariate statistical analyses revealed a significant difference in community composition between clean and cuttings treatments, and three taxa showed significantly reduced abundances in the cuttings treatments. Chemical toxicity of mud components is assumed to be small, and the observed effect was more likely a result of physical properties such as the size or shape of cuttings particles.

Stick-slip oscillations of drag bits by considering damping of drilling mud and active damping system

This paper studies self-excited stick-slip oscillations of a rotary drillstring with a drag bit. In previous researches coupling between torsional and axial vibration was studied for a system with two degrees of freedom and without considering the effects of rotary table, damping of drilling mud and active damping system. In this research, for the first time a complete model is considered. This model is a discrete model with two degrees of torsional freedom and one degree of axial freedom. Both frictional contact and cutting process at bit-rock interface have been considered by bit-rock interaction law. There is a coupling between torsional mode and the axial mode through this law. In this paper, the effects of damping, active damping ratios and bit-rock interaction number have been studied on stick-slip motion. The equations of motion have been solved by numerical method. The technique of solution is Euler-forward finite difference technique. This research shows that by increasing the damping of drilling mud, bit parameter and by appropriate selection of active damping ratios, stick-slip oscillation of bit can be avoided and oscillation of rotary table be damped.

Liquid–solid transition of kaolinite suspensions

Liquid–solid transition, particularly in clay–water systems, can be observed in many industrial applications as well as under natural conditions. This complex process depends on many factors characterising the solid (nature, reactivity, size, morphology of clay particles) and the liquid (chemical properties, pH and salinity). In order to show the influence of rheological properties of the mud system (liquid state) on cake formation (solid state), experiments have been performed with a colloidal suspension of kaolinite. First, the yield stress was measured using a high-resolution rheometer and characterised the initial organisation of the mud system (for three concentrations). Then the liquid–solid transition was investigated on a kaolinite mud using filtration under constant pressure. The filtrate volume and the structural parameters like void ratio, permeability and specific cake formation were taken into account to describe the solidification and the formation of a deposit at different suspension concentrations. The results show that the rheological parameters, which characterise the suspension network, are highly dependent on the initial concentration, whereas the structural parameters of the cake obtained with kaolinite muds are independent of the initial concentration and pressure. There is no correlation between rheological and filtration parameters.

New Water-Based Mud Balances High-Performance Drilling and Environmental Compliance

SummaryA new water-based mud system was successfully introduced as a high-performance, environmentally compliant alternative to oil and synthetic emulsion-based muds (OBM/SBM). Historically, emulsion muds have been the systems of choice when drilling challenging onshore, continental shelf, and deepwater wells to minimize risk, maximize drilling performance, and reduce costs. However, environmental constraints, a high frequency of lost circulation, and the high unit cost of emulsion systems sometimes negate the benefits of their use. Conventional water-based muds (WBM) offer the benefits of environmental compliance, attractive logistics, and a relatively low unit cost but consistently fail to approach the drilling performance of OBM and SBM.The new high-performance, water-based mud (HPWBM) is designed to close the significant drilling performance gap between conventional WBM and emulsion-based mud systems. The system has undergone extensive field testing on very challenging onshore, deepwater, and continental shelf wells that would otherwise have been drilled with oil or synthetic-based muds. This paper provides a detailed, technical overview of the new system, discusses its inherent environmental advantages, and presents case histories comparing performance to offset wells drilled with emulsion and conventional WBM systems.

Brine Imbibition Damage in the Alpine/Colville River Field, Alaska

Abstract Early exploration well tests in the Colville River Field (also known as Alpine) drilled with water-based mud systems exhibited unexplainably high near wellbore residual skin damage as documented by pressure build-up testing. Typical formation damage echanisms including clay reactions, mechanical damage, and gas trapping could not explain the damage. Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation damage mechanism. In situ water saturation is significantly lower than the residual or connate water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formationdamage. This paper documents how successful identification of a unique damage mechanism improved drilling results in a low permeability sandstone. Introduction Exploration drilling results in Colville River prospects consistently demonstrated higher than expected near wellbore skin damage as measured by build-up test analysis. Investigations into more common damage mechanisms such as solids migration and clay swelling could not explain the damage. Early reservoir core studies indicated that residual water saturations from relative permeability curves should be higher than the observed initial water saturations. Later studies with traced core confirmed initial water saturations were considerably less than normal connate water saturations. Further lab work confirmed the water-blocking tendency by measuring water imbibition and permeability recovery during regain permeability tests. Various drilling fluids were tested, with oil-muds consistently delivering lower permeability losses than water-based fluids. For a number of operational reasons, all wells on the first development pad (CD1) were drilled with brine-based fluids. The second pad (CD2) development team accepted the lab results and, after demonstrating the potential benefits of oil-based mud drilling, convinced the drilling team to develop and test a suitable mud program. Initial test results confirmed the lab results and conclusions when Well CD2–47 came in flowing at 300% more than predicted, based on equivalent brine-based mud completions in comparable pay to date. Following this early success, the oil-mud program was expanded and has consistently delivered more productive wells in line with expectations from the lab work. Background The Colville River Field (also known as the Alpine Field) is located approximately 100 km due west of the Prudhoe Bay Field on the north slope of Alaska (see Figure 1)(1, 2). It contains 70 × 106 m3 of recoverable reserves, with approximately 160 x?106 m3 of oil-inplace. Production is from the Alpine Oil Pool, a very fine-grained Jurassic age shallow marine sandstone complex with stratigraphically trapped 40 °API oil. The reservoir is normally pressured and undersaturated. Initial reservoir pressure is approximately 5,500 kPa above the bubble point, and the primary recovery mechanism is solution drive. Figure 2 presents a log and petrophysical overview, and Table 1 provides a summary of key reservoir properties. The field was discovered in 1994 with the drilling of the Bergschrund No. 1. Further delineation confirmed the prospect during subsequent winter seasons, and gravel pad construction began during the 1998 winter season.

A Novel Laboratory Method for Assessing the Erosional Characteristics of Mudcakes

Summary Design and development of superior drilling and drill-in fluids and the assessment of the effectiveness of mudcake cleaning from the borehole wall by cleaning systems require a good understanding of the fundamental phenomena associated with the erosional behavior of mudcakes formed by different mud systems. Because of serious consequences of mudcake erosion on the formation damage potential of drilling muds and mudcake cleaning before a cementation job, it is important to have a suitable, simple, and field-applicable method for predicting the erosional potential of mudcakes formed by muds of different chemical composition. The prediction of erosion behavior is essential to screen and select appropriate mud additives and also to design new mud products for producing good-quality mudcakes on the borehole wall. The technique and technology could provide a suitable means to assess the effectiveness of mudcake cleaning systems and to help design such cleaning systems for removal of mudcake from the borehole wall. Cakes formed by several water-based muds were evaluated using the newly developed technique. The testing has been performed with the simulation of hydrodynamic conditions corresponding to the drill-collar borehole-annular section of a wellbore. The results indicate that the presence of electrolytes significantly increases the erosion coefficient of bentonite mudcake. Ionic fluid-loss additives such as polyanionic cellulose (PAC) and carboxy-methyl cellulose (CMC) reduced the erosion behavior of saltwater-based bentonite mudcake significantly. However, the presence of the polyanionic fluid-loss additive PAC caused a drastic reduction in the erosion characteristic of NaCl-based saltwater mud compared to the presence of the anionic fluid-loss additive CMC. The presence of the nonionic fluid-loss additive, modified starch, shows little improvement of erosional behavior of saltwater-based mudcake. It seems to be that the electrochemical forces of interactions of ionic fluid-loss additives play a vital role in making a mudcake nonerodible. The variation of the erosional characteristics of the mudcakes is attributable to the physical, chemical, and electrical properties of the cake-forming mud additives and also to the nature of the fabrics formed by these additives within the mudcake matrix.

Applications of strongly inhibitive silicate-based drilling fluids in troublesome shale formations in Sudan

For several decades, wells drilled in Sudan Block 6 have experienced serious hole-instability problem related to drilling fluids due to the highly reactive and dispersive shales existing in the Aradeiba and Abu Gabra formations. The problem included washed out hole sections combined with tight hole, as well as serious sloughing shale. Frequent wiper trips were frequently required and logging of the wells was not usually successful. Previously, several conventional inhibitive water-based drilling fluids such as KCl/polymer, KCl/lime/polymer, and KCl/PHPA have been used in this area, but with only marginal improvements in hole stability and drilling performance. Recently, a newly formulated KCl/sodium silicate system, which overcome the fatal drawbacks of the silicate-based mud systems used previously and characterized by the perfect rheological properties and filtration control, was developed and applied to provide the necessary inhibitive character. The first trial well was drilled with this kind of drilling fluid in Sudan Block 6 and the following benefits were observed: (1) Excellent integrity exhibited by drilled cuttings for shale formations; (2) Stable borehole kept with lower mud weight; (3) Reduced wiper trips; (4) In-gauge borehole shown from caliper logs. Later on, five more wells were drilled with the KCl/sodium silicate drilling fluids in this area. It was found that this kind of drilling fluid could fully meet the demands of drilling operations in this area. Case studies were presented in this paper in terms of wiper trip, inhibitive character of cuttings, hole conditions and mud weight. This newly formulated silicate-based drilling fluid is currently applied in Block 3/7 and Block 6, Sudan widely.

Environment friendly fluid loss additives to protect the marine environment from the detrimental effect of mud additives

The exploration and exploitation of hydrocarbon from the ocean dictate the use of environment friendly muds and mud additives to protect the existing wealths such as fishes, coastal areas and other habitats of the ocean. Hence, the preservation of the Australian as well as global ocean environments from the detrimental effects of muds and mud additives dictates the design of better environment friendly drilling mud systems using mud additives having no/negligible environmental impact. This paper describes the fluid loss characteristics of several starches and provides a comparative assessment with respect to a widely used modified starch. Experimental results indicate that some of the starches have static and dynamic fluid loss characteristics similar to or better than those of a widely used modified starch used by the mud industry. The static fluid loss properties measured after thermal treatment at different temperatures indicate that the newly developed starch products can be used as fluid loss additives for drilling boreholes having bottom hole temperature up to 150 °C. The products developed by gelatinization using a reactive extrusion technique have negligible impurities, need no solvent during gelatinization, produce no waste water as a by-product and thus are suitable for environment sensitive areas. The products have been developed from local resources and have lower manufacturing cost and thus expected to decrease the cost of drilling mud significantly.

Inexpensive Directional Wells Drilled Underbalanced With Coiled Tubing

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90783, "Cheap, Directional Wells Drilled Underbalanced With Coiled Tubing: An Experience in the Australian Outback," by Lance Portman, SPE, BJ Services; Lan Nguyen, SPE, Mosaic Oil; and Jim MacArthur, SPE, BJ Services, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September. Coiled tubing (CT) underbalanced directional drilling can be an expensive operation, requiring a significant quantity of specialized equipment and personnel. In some circumstances, the equipment, personnel, and engineering requirements can be reduced, leading to a large reduction in overall operations cost. The full-length paper describes equipment and method simplifications made during a four-well underbalanced directional-drilling campaign in Queensland, Australia. Introduction CT drilling is not new. More than 10 years have passed since the first directional wells were drilled with CT. Simple vertical drilling and milling applications date back even further. Many thousands of wells have been drilled vertically with CT, but the number of directional wells drilled with CT is less than 1,000. CT directional drilling has established itself in only two regions. The first is western Canada, where CT is used to drill underbalanced horizontal well sections. The second is Alaska, where CT is used to construct sidetracks, drilling through the completion tubulars. CT can provide significant advantages over jointed-pipe methods, particularly for underbalanced drilling and for sidetracking out of smaller completion strings. However, the incremental cost of using CT historically has deterred operators from using this technique. Background A four-well drilling campaign was begun in the southwest Surat-Bowen basin. The wells were approximately 373 miles west of Brisbane. The drilling target was the Showgrounds sandstone and Rewan-formation sands. These sands have been produced for more than 20 years and are penetrated by hundreds of wells. These wells typically were drilled overbalanced with a potassium chloride (KCl)/polymer mud system, and they experienced severe formation damage. Typical skin for wells after completion is 20 to 80. The goal was to convert some of the old damaged vertical wells into horizontal wells drilled underbalanced. Formation Properties. The target zones are approximately 100 ft thick and consist of layered sandstone, siltstone, and mudstone. Permeabilities average approximately tens of millidarcies, although streaks exist with 2 darcies. Rock strength is between 12,000 and 27,500 psi, and the Rewan formation is known to be very abrasive. Kaolinite clay averages 69% of the total clay content and illite 15%. The formation is water sensitive. Both the pay zone and the layers above were believed to be competent rock. No washout was observed in wells previously drilled through these zones. Formation temperatures were approximately 176°F. Produced Fluids. Most wells are expected to produce wet gas and/or gassy oil, although there was uncertainty as to the amount of gas and oil that would be produced. Oil in this region typically is 46°API, and no hydrogen sulfide is present. Drilling Program The drilling plans called for pulling the existing completions, milling a window in the existing 5½-in. casing strings, and then drilling a build section over approximately 328 ft of true vertical height followed by several hundred feet of horizontal hole. The 4½-in. horizontal hole would be drilled underbalanced, and the 4½-in. build section would be drilled overbalanced.

Brine Imbibition Damage in the Colville River Field, Alaska

Summary Early exploration well tests in the Colville River field (also known as the Alpine reservoir) drilled with water-based mud (WBM) systems exhibited unexplainably high near-wellbore residual skin damage documented by pressure-buildup testing. Typical formation-damage mechanisms, including clay reactions, mechanical damage, and gas trapping, could not explain the damage. Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation-damage mechanism. In-situ water saturation is significantly lower than residual or connate-water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formation damage. This paper documents how successful identification of a unique damage mechanism improved drilling results in low-permeability sandstone.

Drilling Salt Formations Offshore With Seawater Can Significantly Reduce Well Costs

Summary The rate of penetration (ROP) increases significantly if salt formations are drilled with undersaturated fluids. This is especially true when drilling riserless. Of primary concern is the amount of hole enlargement that will occur. However, if managed, then a step change in drilling performance and costs can be achieved. This paper presents in detail the results of a comprehensive and large-scale laboratory testing program performed on outcrop salt samples that replicate drilling salt formations with undersaturated drilling fluids with flow rates of up to 1,000 gal/min (gpm). The laboratory testing program includes tests performed in a computerized tomographic (CT) scanner to map hole enlargement in real time, as well as variously sized borehole leaching tests with borehole diameters of up to 6 in. Flow rates are scaled to produce comparable levels of turbulence occurring in the field. An analytical hole-enlargement prediction model is presented that incorporates the effects of ROP, pump rate, drill-fluid saturation, dissolving salt drill cuttings, and salt leaching from the borehole wall. This model accurately predicts to within 10% the measured hole enlargements produced in the scaled laboratory tests for a wide range of flow rates and fluid saturations. Predictions of field performance are made, and the implications of the predicted hole geometry are discussed. Provided that high rates of penetration are realized, acceptable hole geometries will result, even when pumping seawater at flow rates of up to 1,600 gpm. A field application is described whereby the historical practice of drilling the last 200 ft of the 20-in. hole into salt using a saturated brine drilling fluid was discontinued in preference to the continued use of seawater. The competing influences of increasing rate of penetration and avoiding the cost of a sacrificial mud system, offset by the increased cost of cement, resulted in cost savings of U.S. $250,000 per well. Implemented in a multiwell subsalt development, cost savings of more than U.S. $1.5 million will be realized in the drilling program. Further applications of this technology are now being sought.

Successfully Replacing Oil-Based Drilling Fluids With Water-Based Drilling Fluids: Case Study Demonstrates Value of Extensive Planning and Execution in an Extended-Reach Well

Summary An extended-reach well was planned and successfully drilled with a water-based drilling fluid in an area where wells historically have been drilled with mineral oil- and ester-based drilling fluids—the North Sea central Graben. The high cost of cuttings drilled with inverts that must be shipped to shore for processing and disposal coupled with the potential shutdown of drilling operations in times of bad weather (when cuttings could not be transferred from the rig to supply vessels) led the operator to revisit the use of water-based drilling fluids, especially in the large-diameter hole section in which large amounts of cuttings are generated. However, many water-based systems have been used in the central Graben with little success. The need to develop a stable, shale-inhibiting, waterbased mud (WBM) system capable of performing well in extended-reach drilling (ERD) applications was identified. Extensive prewell modeling of wellbore stability in problematic shale zones and of hole cleaning in the large-diameter interval contributed to the success of this challenging project. This article discusses the planning, preparation, and successful drilling of the intermediate interval with a water-based drilling fluid.

On the physical and chemical stability of shales

The stability of clay-rich shales is profoundly affected by their complex physical and chemical interactions with drilling fluids. In this paper, an attempt is made to clarify the intricate links between transport processes (e.g. hydraulic flow, osmosis, diffusion of ions and pressure), physical change (e.g. loss of hydraulic overbalance due to mud pressure penetration) and chemical change (e.g. ion exchange, alteration of shale water content, changes in swelling pressure) that govern shale stability. It is shown that shale–fluid interactions can be manipulated to enhance cuttings and wellbore stabilization as well as improving hole-making ability in shale formations. The mode of shale-stabilizing action of a wide variety of water-based fluid additives is discussed and the merits of various mud systems are ranked. It is shown that shale stabilization normally achieved using oil-based/synthetic-based muds is now becoming achievable with economical and environmentally friendly water-based drilling fluids.

Real-Time Specific Energy Monitoring Enhances the Understanding of When To Pull Worn PDC Bits

Summary Knowing when to change dulled bits can significantly reduce costs, which can be particularly important in high-cost environments. However, current techniques are based more on speculation and hope rather than science. The concept developed to dramatically improve this inefficient decision process involved measuring the mechanical energy input at the drill rig floor, calculating the drilling specific energy (SE), checking the current formation type with real-time downhole gamma ray (GR) readings, comparing the SE with the benchmark new-bit SE, and then using these values to assess the bit's "dull" state. This method has been proven to work in synthetic-based mud systems in which balling does not mask the bit's dull condition. It was imperative that the operator proved that this process worked in water-based drilling fluids that had replaced earlier synthetic muds because of environmental concerns, cost, and improved performance in water-based mud (WBM). Recently, the operator established that this process worked in water-based mud systems treated with antiballing chemicals. The case studies in which this methodology was developed are presented and discussed.

タイ湾でのガス田開発

It has been over 30 years since MOECO was awarded exploration rights in the Gulf of Thailand. MOECO has been carrying out exploration for oil and gas in this area since 1971. During that period, the Erawan gas field was discovered in Thailand in 1973 and its production started in 1981. In turn, other gas fields were discovered. Currently, the average gas production is 740 mmcf per day produced by 13 offshore gas fields. In 1999 the Pailin gas field, Block B 12/27, in the gulf of Thailand began production. The current gas production of the Pailin field is approximately 330 mmcf per day. In order to achieve long term financial success in the gulf of Thailand, where geological structures are extremely complex and reservoir extents are marginal, an operator has been required to drill many wells at an absolute minimum cost.Throughout the last 20 years of these field's productive lives, important initiatives have been undertaken by UNOCAL, as an operator, to meet numerous technical and economic challenges. I will introduce an overview of some of technical challenges in the fields, such as 3 D seismic, drilling innovation including simplified and slimhole well design, PDC bit, mud system, unitized wellhead, installation of top drives, steerable system and adjustable guage stabilizer, completion design, MWD etc.