Knowledge of swelling properties of shale-oil formations as well as the effects of various drilling fluids, including both water-based and oil-based muds (OBMs), which are of critical importance to wellbore-stability problems, requires a better understanding of shale-oil properties. Drilling through shale-oil formations is highly problematic and imposes substantial costs to the operators owing to wellbore-stability problems. These problems include, but are not limited to, tight holes, stuck pipe, fishing, sidetracking, and well abandonment. To more efficiently and effectively drill through these formations, we should better understand their properties. Only few experiments have been conducted on shale-oil samples to better understand their properties. Most experiments performed thus far were run on common shale core samples, which are significantly different from shale-oil samples in the matter of mineralogy and mechanical properties. Subsequently, the results of those experiments cannot be equally applied to shale-oil and shale-gas formations. In this study, we first determined the mineralogy of shale-oil core samples from the Eagle Ford field and then investigated the swelling properties and cation exchange capacity (CEC) of the core samples in the laboratory. Experiments have been conducted with the samples partially submerged in distilled water, potassium-chloride (7% KCl) brine, and OBM. Several experiments have been performed using strain gages to measure lateral, axial, and diagonal swelling in both submerged and non-submerged areas. We also performed unconfined compressive strength (UCS) tests to investigate the effect of the invasion of various drilling fluids on the compressive strength of the core samples. The experimental setup was modified to accommodate five linearly variable displacement transducers (LVDTs) to measure Young's Modulus (E) and Poisson's ratio ( v ). Various experiments were run to quantify the effect of temperature on the rock compressive strength, E, and v . Experiments have shown a distinct change in the mechanical properties of the rock. The results demonstrate that the swelling properties and CEC of the shale-oil core samples are different from the common shale core samples. This study proposes the quantification of the shale/fluid properties, the interaction, and the effects of different fluids on rock properties in unconventional reservoirs. This paper presents and documents the differences in the swelling properties between conventional and unconventional shale. The results of the study will help us to more precisely understand unconventional shale-oil rock properties and can be used to design a more effective drilling fluid for field applications, as well as more accurately predict the mechanisms of formation failure.

Environmental impact has become business critical as we have been unable to crack certain issues to the degree expected for our industry. It is the central challenge for the continued development of shale markets, as it has been offshore. In a customer survey completed in the first quarter of 2012, a diverse group of operators, drilling contractors, and service companies identified their top three challenges for shale development: pricing, inexperienced personnel, and—of paramount importance—environmental impact. The industry recognizes the need for reduced environmental impact, but what do we need to achieve it? In the aforementioned survey, many operators and drilling contractors expressed looking to oilfield service and supply companies for continued innovation with the expectation that they continue to be to be forward-thinking and present ideas that provide value. The industry has two primary means for reducing environmental impact of its operations: processes (operator and contractor-driven) and equipment (service and supply-driven). This paper proposes that the two must work hand-in-hand. It explores the opportunity to take this further: identifying critical steps such as process design for reduced environmental impact with lower-impact technology and industrial engineering. The dual approach is needed to affect large-scale change. This paper will examine the positive impact of the implementation of select environmental technology can have on oilfield economics from the perspective of an oilfield equipment, technology, and services provider. It aims to: Demonstrate a case for environmental solutions Establish the importance of improved environmental performance for market access Identify areas in which operators evaluate environmental impact Discuss the technology opportunities available to operators Recognize and quantify the performance and cost benefits of aforementioned technologies.

Abstract Full-scale laboratory testing was conducted under a joint industry and Department of Energy program titled "Optimization of Deep Drilling Performance; Development and Benchmark Testing of Advanced Diamond Product Drill Bits and HP/HT Fluids to Significantly Improve Rates of Penetration." In total, seven bits and twelve different drilling fluids were tested in three different rocks at a variety of drilling parameters. Phase 1 results have been reported in a previous paper (Arnis Judzeis et al., 2007). This paper presents the results from Phase 2 of the study. The goal of Phase 2 testing was to evaluate bit features and mud additives that might enhance ROP under high-pressure conditions. The test protocols developed in Phase 1 to simulate Arbuckle play and Tuscaloosa trend drilling at pressures in excess of 10,000 psi were employed to evaluate these features. Significant findings of Phase 2 include the following: Mud additives can substantially enhance ROPs in high-pressure conditions and may play a larger role than bit design features. A 16-ppg cesium formate brine increased ROPs 100% as compared to 16-ppg oil-based mud in Carthage marble and Mancos shale. The cesium formate improved ROPs by increasing both the efficiency and the aggressiveness of the bit. A 16-ppg oil-based mud weighted with fine particle size (D50 ˜ 1–3 microns) manganese tetroxide increased ROPs in Crab Orchard sandstone 100% as compared to a similar mud weighted with conventional barite. The manganese tetroxide improved ROPs by increasing the efficiency of the bit, but did not have a measurable effect on bit aggressiveness. Phase 2 tests continue to support the conclusion of Phase 1 that specific energy consumed while drilling is substantially higher than the confined compressive strength (CCS) of the rock. Introduction An important factor in future gas reserve recovery is the cost to drill a well. This cost is dominated by the rate of ROP that becomes increasingly important with increasing depth. The object of this study is to improve the economics of deep exploration and development. In September 2002, the U.S. Department of Energy's National Energy Technology Laboratory awarded funding to the Deep Trek program to assist in its goal "…to develop technologies that make it economically feasible to produce deep oil and gas reserves…" and "…focus on increasing the overall rates of penetration in deep drilling." The researcher's proposal was to test drill bits and advanced fluids under high-pressure conditions. Phase 1 of the proposal was to establish a baseline of performance and provide data upon which to make design improvements. Phase 2 was to establish improvements in design.

Abstract Kick detection in oil and synthetic-based fluids has been a major concern for the industry for decades. Due to solubility issues, kick detection may be delayed and resulting well control operations may be problematic. Use of the Micro-Flux Control (MFC) method potentially offers a better way to address this problem in the same way it has been successfully demonstrated to work using water-based fluids (WBM). To check the performance of the MFC method while using oil-based mud (OBM), a series of full-scale tests were conducted at Louisiana State University PERTT Laboratory using natural gas injected into test wells containing an 11-ppg 70/30 diesel/water OBM. Performance results were compared with results previously obtained with WBM gathered at the same facility. The excellent and consistent character of the test results obtained encouraged the use of the MFC on a well to be drilled in Texas for Chevron. The well plan called for using OBM with mud density up to 17.4 ppg, at an anticipated depth of 13,000-ft. This would be the second well drilled with the MFC method, following one drilled in Brazil for Petrobras using WBM. The paper presents the results obtained during the one -week long live well testing at LSU as well as details of the first field test of the MFC system on the actual well drilled with OBM in Texas. The results confirmed the ability of the MFC system to detect very small influxes of natural gas into OBM with subsequent control of the influx accomplished in a way very similar to that used with WBM. Several other tests were also performed in both wells to explore possible additional uses of the MFC system. These included dynamic leak-off and formation integrity tests, behavior with multiple kicks inside the wellbore simultaneously, identification of ballooning or "breathing" during connections, and early detection of loss of circulation. All of the results obtained in both test scenarios confirmed the potential value of the MFC system for identifying and dealing with the above listed issues when conducting drilling operations utilizing OBM. Introduction Despite several challenges the industry faces when employing OBM, its use is still common. Environmental considerations are probably the biggest issue, but the technical advantanges offered by OBM in difficult drilling conditions often compensate for its choice. Today, OBM is the preferred choice for many wells located in deepwater, for HPHT applications, and for wells with chemical related wellbore instability. These challenging drilling scenarios have previously raised significant concerns related to detection of kicks and subsequent well control operations because of the solubility of natural gases in the hydrocarbon fraction of the fluid. Pit gain and increase in return flow rates are widely used as primary kick indicators. However, the roll and heave movements on floater drilling vessels and the relative inaccuracy of today's measurement methods may often result in high kick volumes in the wellbore. Gas solubility has been blamed for causing problems in early detection of the kick when using OBM. Previous studies done by O'Brien1, Thomas et al2, O'Bryan3 and O'Bryan and Bourgoyne4 have shown that there will be very little or no increase in pit level as the gas dissolves in the OBM over time and the detection of kicks is indeed more of a problem than in WBM. Cockburn5 added that "oil based muds with gas in solution, reduce the time the driller has to react to this potentially dangerous situation." Recognizing the criticality of well kick volume, or kick tolerance, early detection could result in a significant increase in drilling operation safety and efficiency. Orban et al6 stated that "The danger of undetected influxes grows with the increase of average well depth, drilling through deep water and the tendency to drill with lighter mud. The detection of influx is still commonly based on unreliable and/or inaccurate methods." However, using a closed-loop system and accurate flow measurements brings the possibility and potential for early gas kick detection in OBM before the gas has time to go into solution. In addition, coupling early detection with a computer controlled hydraulic choke, the MFC method minimizes the total volume of gas in the wellbore.

Abstract Conventional drilling and completion fluids containing weighting solids or hydrocarbons or halide brines can create problems with hydraulics, well control, well integrity and well productivity in HPHT operations. The negative influence of conventional fluids on drilling and completion operations can be sufficiently serious to compromise safety and degrade the economics of challenging HPHT field developments. Formate brines have been developed specifically to provide improved drilling and completion fluids that are free of the troublesome components found in conventional fluids and therefore better suited to meet the needs of oil companies involved in difficult HPHT well constructions. Formate brines have been successfully used as reservoir drill-in, completion, workover and suspension fluids in more than 130 HPHT well construction operations over the past 10 years. These applications have included 100 cases in which high down-hole pressures have necessitated the use of cesium formate brines for well control purposes. Some 15 applications of cesium formate brines to date have been HPHT reservoir drill-in operations in high angle wells where operators considered that conventional fluids could create a safety risk and adversely effect project economics. We review the published information on the field performance of the cesium formate brines in HPHT applications, and conclude that the novel benefits of the technology that were first promised some 15 years ago during the early product development phase have now been fully validated. Introduction The objective of the drilling and completion process is to safely deliver high quality wells that are optimized in terms of providing shareholder value: Best well productivity at lowest drawdown Best well integrity and longest structural lifetime Lowest well construction cost Lowest environmental impact and liability exposure Best reservoir information capture The choice of drilling and completion fluid used in a well construction operation has a critical influence on the extent to which an operator can meet this objective. In particular the fluid's performance will play a significant part in determining whether or not an operator meets its key performance indicator targets in the following areas: Time to drill and complete Well control and safety incidents Well integrity Well lifetime and maintenance costs Well productivity index Waste management costs Logging capability and interpretation Environmental footprint and impact Exposure to liability (short- and long-term) The drilling fluid chosen for the upper well sections must offer a host of functionalities: Ability to maintain the integrity of weak rocks Ability to minimize fluid loss into permeable rocks Ability to provide stable well control Ability to efficiently transfer hydraulic power Ability to move cuttings to the surface Provide steel/steel and steel/rock lubricity Provide protection against all forms of corrosion Allow formation evaluation Pose little or no hazard to rig personnel Have little or no adverse effect on the environment Have little or no adverse effect on elastomers If the drilling fluid is to be used in reservoir sections without further intervention it must cause minimal change to the native permeability of the reservoir rock in the near wellbore area. The drilling fluid filtrate must also be compatible with other filtrates that might leak-off from subsequent cementing and completion operations. A completion fluid should have the same overall properties as a reservoir drilling-in fluid and, ideally, should be the same fluid minus any drilled solids.

Abstract Water-based mud designs as alternatives to oil-based or synthetic-based muds are compared versus history of use. Water-soluble designs and water-insoluble designs are discussed as well as a combination approach used by Woodside Energy to drill on the Northwest Shelf, Offshore Australia. Perfornance of a water-based 2-phase polyglycol mud system containing a Drilling Enhancer with an appropriate bit design was technically and economically equivalent to that with a synthetic-based mud. Introduction The first use of oil as a drilling fluid was not documented but probably occurred shortly after the introduction of rotary drilling around 1890 1,2 . The early uses were for well completions but broadened with time to include coring, stuck pipe release/prevention, annulus packs, wellbore stabilization (especially in shales), HPHT applications, corrosive environments, plastic salt 3 and directional drilling. Oil-based muds (OBM) and Synthetic-based muds (SBM) are believed to excel at these applications through elimination of water in the external phase and the positive contribution of the oil (or synthetic). The undesirable characteristics of water include the ability to impede hydrocarbon flow through porous rocks, hydration/plasticization and/or disintegration of cuttings, loss of wellbore support through pore pressure elevation, the ability to dissolve salt and to corrode metals. The desirable characteristics of the oil/synthetic fluid include better lubrication, higher boiling points and lower freezing points. Despite their broad applicability, high performance and capacity for reuse, OBM/SBM's also carry a higher unit cost (especially SBM), are more difficult to mix, more prone to lost circulation and less environmentally acceptable than water-based muds (WBM). These disadvantages have led to the development of water-based drilling fluids that attempt to duplicate oil-based or synthetic-based mud performance without the limitations. The starting point for these water-based fluid designs is typically control of clay/shale hydration and swelling. Early "High Performance" Water-Based Muds. Well abandonment due to borehole instability was reported as early as the beginning of the 1920's drilling with WBM near salt domes in the US Gulf Coast 4 . The problem was identified as "heaving shale" which referred to any shale that sloughed into the hole to the extent that drilling was adversely impacted. The cause was identified as water sensitivity and the mechanism was believed to be clay swelling when the formations contacted water in the WBM. Loomis in his 1931 patent 5 claimed simple hydrolytically stable salts such as calcium chloride to reduce the swelling and osmotic pressure believed to exist between the mud and borehole by lowering the water activity. In the years that followed a variety of other relatively simple and stable electrolytes were also tried including sodium chloride, zinc chloride, sodium nitrate, hydrated lime, potassium chloride and gyp. Performance in some applications was supplemented with more complex metal-organic salts or complexes such as calcium tannates & lignosulfonates, chrome & ferro-chrome lignosulfonates and chrome lignites. Sodium silicate, a reactive salt, also received early attention as did ethoxylated phenol, the first polyglycol widely used in the industry (see below). While all of the above are capable of suppressing clay swelling and all have enjoyed their turn as the basis for "mud of the month" fame at least once, clay swelling is only part of the problem. Near wellbore pore pressure elevation from filtrate invasion is at least as important which reduces the effective stress at the borehole wall and pressure support of the borehole is lost leading to wellbore failure 6 . Micro-fracturing or even macro-fracturing from drillstring vibration, swab/surge/pump mud pressure oscillation and fluid/rock temperature differences 7 only accelerate this failure by increasing near wellbore permeability 8 . Early "High Performance" Water-Based Muds. Well abandonment due to borehole instability was reported as early as the beginning of the 1920's drilling with WBM near salt domes in the US Gulf Coast 4 . The problem was identified as "heaving shale" which referred to any shale that sloughed into the hole to the extent that drilling was adversely impacted. The cause was identified as water sensitivity and the mechanism was believed to be clay swelling when the formations contacted water in the WBM. Loomis in his 1931 patent 5 claimed simple hydrolytically stable salts such as calcium chloride to reduce the swelling and osmotic pressure believed to exist between the mud and borehole by lowering the water activity. In the years that followed a variety of other relatively simple and stable electrolytes were also tried including sodium chloride, zinc chloride, sodium nitrate, hydrated lime, potassium chloride and gyp. Performance in some applications was supplemented with more complex metal-organic salts or complexes such as calcium tannates & lignosulfonates, chrome & ferro-chrome lignosulfonates and chrome lignites. Sodium silicate, a reactive salt, also received early attention as did ethoxylated phenol, the first polyglycol widely used in the industry (see below). While all of the above are capable of suppressing clay swelling and all have enjoyed their turn as the basis for "mud of the month" fame at least once, clay swelling is only part of the problem. Near wellbore pore pressure elevation from filtrate invasion is at least as important which reduces the effective stress at the borehole wall and pressure support of the borehole is lost leading to wellbore failure 6 . Micro-fracturing or even macro-fracturing from drillstring vibration, swab/surge/pump mud pressure oscillation and fluid/rock temperature differences 7 only accelerate this failure by increasing near wellbore permeability 8 .

Abstract Major problems are often encountered in relaxed basins when extended reach wells are drilled through depleted reservoirs. As wellbore inclination increases, the imbalance between vertical and horizontal stresses can cause formation breakouts leading to increased cuttings and increasing the potential for stuck pipe. Higher mud densities can stabilize the imbalance and facilitate cuttings transport, but increase the risk of differential sticking and lost circulation. Additionally, higher mud densities can create fractures that take mud while drilling and return mud during connections. This ‘ballooning’ or ‘weeping’ complicates the correct diagnosis and increases the risk of losing the well. Early identification of these competing mechanisms can be critical to successful drilling. Real-time resistivity-at-the-bit images are now possible to aid diagnosis, but are currently limited to water-based muds, and a limited range of conductive oil-based muds (OBMs). Nevertheless, conventional resistivity measurements can still be used in wells drilled with OBM. A case study is described of a highly deviated Gulf Coast well drilled with synthetic OBM that penetrated a severely depleted reservoir. Based on the data collected the original assumption that depleted sands were the only source of lost return zones was in error. The losses were found to be in the bounding shales as well. After losing two wellbores, the project was abandoned due to wellbore instabilities and limited reserves. Investigations into the lessons learnt highlight how multiple passes with both resistivity and annular pressure measurements could have been used to diagnose the location and mechanism of borehole failure, and hence suggest appropriate action. Indeed, the resistivity measurements were found to be responding to induced fractures hours before any changes in equivalent circulating density (ECD) or significant drilling observation. A methodology is given for diagnosing drilling induced fractures from the real-time measurements, so that remedial actions can be promptly taken. Success in future operations will come from including these new methods into the drilling plan. Introduction The use of resistivity images to distinguish between natural and drilling-induced fractures has been described by Rezmer-Cooper et al. 1,2 While drilling, it is important to distinguish natural features from those induced by the drilling process so that the drilling program can be modified to minimize the impact of the induced fractures. A geological analysis of borehole images includes the search for open natural fractures. Wrongly identifying drilling-induced fractures as natural fractures results in an optimistic forecast, and could lead to incorrect remedial procedures being recommended for the drilling program. However, even though real-time images are now possible, and can now complement existing conventional real-time logging-while-drilling (LWD) measurements, their use is limited to water-base muds or conductive oil-base muds, which are still in their infancy, and have yet to gain wide acceptance.

Abstract The Anglia gas field was originally developed in the late 1980s with the first wells being drilled with mineral oil-based mud in the reservoir sections. In most cases, production from the original wells was below expectation and only five years later, plans were being made to re-develop the field in order to maintain its economic viability as a gas producer, and meet gas delivery commitments. Well-bore placement and drilling fluid selection were determined to be critical factors in ensuring the success of planned in-fill wells. This paper reports on the planning and testing which was conducted during the selection of the drilling fluid for the reservoir phase of the new wells, changes in drilling practice and the subsequent production obtained from utilising this new approach, in comparison to the production from the original wells. Reasons for the poor production from the first phase of the development are discussed. Due to the more complex trajectories and longer well-paths required by the well design team, additional difficulties were created for the drilling fluid, notably that of lubricity. Further testing is described in the paper, where the best combination of good lubricity and minimal formation damage was sought. Final production data on three wells drilled during 1997–9 are reported. The overall experience confirms that a detailed drilling fluid selection process which takes into account key reservoir-specific factors, combined with a holistic approach to the drilling and completion of the reservoir section of a well can significantly enhance its resultant productivity. Introduction The advent of sand-face completions during the late 1980s and early 1990s drove the development of specialised drilling fluids (now usually referred to as "drill-in" fluids) for use in the reservoir section of a well 1 . Cased and perforated completions had been run in wells typically drilled with little or no consideration for the mud type and its potential for formation damage on the assumption that the perforation tunnels would extend beyond any near well-bore damage. In the North Sea during the 1980s, special consideration from an invasion perspective was only given to drilling fluid design for coring applications. In such cases, high oil content or "all oil" muds were frequently used, although here, the emphasis was on the use of "native state" fluids, which would not alter the innate wett ability of the core or otherwise prevent meaningful analysis of the target formation. The development of the Anglia field covers a period spanning the above transition. The early production wells were drilled with conventional invert oil emulsion muds in the 12¼" and 8½" (reservoir) sections with little if any difference in terms of fluid composition between the two sections. The later wells (A6 to A8, drilled during 1997–99) continued to use oil-based mud in the 12¼" sections but utilised a specifically designed, water-based drill-in fluid for the reservoir sections in all cases. The considerations involved in making this alteration to the mud system selection, together with the subsequent effects on the performance of the Anglia field are the subject of this paper. Jones et al 2 have previously reported on the benefits of a specific design process for the selection of a drill-in fluid as a necessary step in optimising the productivity of wells; here we report on the application of this process to a multi-well project. Historical Background The Anglia Field is located in blocks 48/18b and 48/19b in the U.K. sector of the Southern North Sea, approximately 55 kilometres north-north east of Bacton in Norfolk and 90 km east of The ddlethorpe in Lincolnshire (Figure 1). The field is located in the area of the inverted Sole Pit basin close to the Dowsing Fault zone. The reservoir interval comprises the Permian Rotliegendes Sandstone formation. The Anglia Field has eight producing wells. Six wells, in the Eastern half of the field, are tied back directly to the Anglia ‘A’ platform, a small, normally unattended, tripod.

IADC Members Abstract Differential sticking has a major impact on drilling efficiency and well costs. Although some problems can be related to the characteristics of rock formations, or to drilling parameters not related to drilling mud properties, it is widely accepted that the mud formulation and condition strongly influences the risk and severity of differential sticking incidents. In this paper we use our own laboratory data and information from industry publications to formulate the mechanisms of differential sticking and the key drilling mud parameters that can influence the process. Using this knowledge, we have built a simple and robust device for measuring the sticking properties of muds in the laboratory or at the well-site. This device comprises a half area HTHP fluid loss cell which is modified to allow a metal sphere to be placed in contact with a growing mud filtercake The torque required to rotate the sphere free from the mud cake is determined using an electronic torque gauge. We find that a plot of torque against the 3/4 power of time (this power term derives from the build-up of cake around a spherical object) gives a linear fit to the data, and that the slope of this line is indicative of the sticking potential of the mud. An extensive analysis of laboratory-mixed and field muds indicates that the test gives a good indication of mud condition and allows the user to investigate various options for reducing the sticking potential of the fluid. This information is useful both in the initial selection of mud type and in making technical and economic analyses of various mud treatment options. In addition to the laboratory evaluation described above, the sticking device has been used in several wellsite tests with encouraging results. Some of these are described. Introduction Stuck pipe is a major non-productive cost to the drilling industry. A survey presented by a major drilling contractor in 1992 estimated that over a 15 month period, 36% of all reported drilling problems world-wide were due to stuck pipe. Stuck pipe problems are generally divided into 2 categories: mechanical sticking (up to 8 sub-sets have been identified) and differential sticking. The proportion of incidents classified in each category varies with the type of well and the geographical area; for example, one oil company estimated that in its North Sea wells, 29% of the cost of stuck pipe was due to differential sticking and 70% due to mechanical sticking while in the Gulf of Mexico, differential sticking was the dominant problem at 61% of the total cost of incidents. The same company estimated that the cost of stuck pipe to the industry is in excess of $250 million each year. In this paper we focus on the problem of differential sticking. We will examine the mechanisms of differential sticking and will review published experimental methods that have been used to investigate the phenomenon, particularly those which relate to mud formulation and properties. We will then describe a simple differential sticking test (called for convenience the "Stickance" test) and its application in the laboratory and at the well-site for the study and prevention of differential sticking. Mechanisms of Differential Sticking Mechanisms of differential sticking were first proposed in the late 1950's by Helmick & Longley and Outmans: P. 493

SPE Members Abstract A recently developed, environmentally safe, water-based drilling fluid has been given its first field trials. The successful field tests have shown that the fluid is indeed very shale stabilizing, has the ability to solve some mud related drilling problems, is easy to formulate and maintain, and is non-hazardous and environmentally safe. These results have corroborated the laboratory testing which had shown that the fluid stabilizes shales by the same mechanism as does oil-based muds. The drilling fluid, which is based on methylglucoside (MEG), thus has the potential to replace oil-based drilling fluids in many operational areas. The use of this drilling fluid could reduce or eliminate costly disposal of oil contaminated drilled cuttings, minimize health and safety concerns, and minimize environmental effects. Introduction Oil-based drilling fluids are used routinely in many operational areas. These applications are normally in areas where the drilling situation requires the advantages provided by the excellent performance of oil-based drilling fluids. However, in many of these areas the use of oil-based drilling fluids is cause for increasing concern due to environmental restrictions and disposal costs. Water-based drilling fluids that can give oil-mud like performance are needed for use in these situations. Any water-based replacement fluid must possess those characteristics that make the oil-based fluid a good choice for the given application. Oil-based drilling fluids can provide superb borehole stability, are highly resistant to contamination, and are stable under high temperature conditions. The use of oil-based muds also can give excellent drilling performance when used in conjunction with PDC bits. The water-based mud must replicate the performance of the oil-based fluid. A new water-based drilling fluid system has been developed that has an excellent chance of replacing oil-based muds in many applications. The fluid is based on methylglucoside (MEG). As indicated by its structure as shown in Figure 1, methylglucoside is a chemical derivative of glucose. Methylglucoside is supplied as a liquid containing 70% solids. As supplied it contains about equal portions of the alpha and beta forms of methylglucoside. P. 605

SPE Members Abstract Gas kicks in oil- and water-based mud have been studied in an inclined research well. One of the main objectives has been the study of early kick detection. Data on pit gain, stand pipe pressure and mud return flow have been systemized in all the kicks in order to evaluate the performance and sensitivity of these parameters. The performance and sensitivity of these parameters. The sensitivity of the detection parameters have also been compared for various kick types. The results show that several surface detection parameters are necessary in order to optimize detection. The reduction in pit gain due to gas solubility in OBM is shown to be significant The mud return flow was the most sensitive parameter in OBM. In OBM also pit gain and stand pipe pressure were valuable for kick detection. New detection signs have been found on the return flow signal in OBM and in kicks with MWD pressure pulsing. pulsing Introduction In October 1988, 24 full scale gas kick experiments were performed at Ullrigg in Stavanger by Rogaland Research. performed at Ullrigg in Stavanger by Rogaland Research. The experiments were carried out in a 2020 m long research well with maximum inclination of 63 deg. Data from 19 downhole and surface sensors were collected in order to study the development and the control phase of a gas kick. Among the parameters that were systematically varied, were mud type, mud density, gas type, gas concentration, mud flow rate and injection depth. In addition, some of the kicks were performed with MWD pulsing. performed with MWD pulsing. One of the main objectives of the gas kick experiments was to study early kick detection. The data from the available kick detection parameters were systemized in all the kicks, in order to study how differences in the drilling conditions affected the kick detection. The time from start of an influx to a kick is detected, is of great importance. If the kick is detected early, the amount of gas that enters the well can be reduced, and thereby the maximum pressure that will occur at a given location in the well can be reduced. It is therefore of great importance to evaluate the existing kick detection parameters, and also to develop new methods that could be used instead of, or in addition to the present standards. KICK DETECTION Monitoring of drilling parameters provide at least three parameters for kick detection. These are pit gain, mud return parameters for kick detection. These are pit gain, mud return flow (or actually delta flow) and stand pipe pressure. Normally pit gain is used-as kick detector. However, also mud return flow rate (or delta flow) and stand pipe pressure can be used to detect gas kicks. None of these require sophisticated downhole electronics or advanced signal processing. processing. Pit gain Pit gain Pit gain has been the simplest and most widely used kick Pit gain has been the simplest and most widely used kick detector. The fluid level in the pit or in the trip tank has been monitored, and a volume increase has been considered as a possible kick sign. possible kick sign. P. 775

Abstract This paper reports a general hydrodynamics theory of steady-state isothermal flow of non-linear viscoplastic drilling muds through the annular space of the well. The theory has been developed to fit an optimal circulation program design for conditions of high probability of circulation losses and/or formation fluid kickings. Mud compressibility problems are discussed as well as the adequacy of problems are discussed as well as the adequacy of different rheological models to the behaviour of various mud types. There are briefly stated fundamentals of the engineering procedure used to design optimized rheohydraulics programs for drilling wells. The said procedure with the corresponding computer program procedure with the corresponding computer program has been successfully used for drilling in deep thick abnormal pressure reservoirs of several Soviet oil and gas fields (Tengiz and others). Introduction Specific features of drilling in deep thick abnormal pressure reservoirs are due to the decreasing of formation pressure and fracture gradients with depth. Frequently, this circumstance leads to a situation in which the mud density necessary to cope with the formation pressure in the top of the reservoir becomes excessive as to the bottom part of the reservoir. Such being the case, pre-conditions are created for mud losses in the pre-conditions are created for mud losses in the lower part of the reservoir and for kickings in its upper part. Hydrodynamic pressures arising in the annular space of the well while it is being circulated or in the course of round trip operations, make the "hydrodynamics consistency interval" even smaller and increase formation fracturing and/or kicking risk. To drill in such conditions it is necessary to ensure safe borehole pressure values eliminating as kickings so circulation losses irrespective of what technological operation is in progress. That's why a drilling hydraulics program shall be aimed not at the bit hydraulics optimization but at the optimization of the annular hydrodynamics. To develop hydraulics programs of this kind it is necessary:- to determine as exactly as possible formation pressure and circulation loss pressure values for formations being drilled;- to determine exact hydrodynamic pressure values in the annular space while drilling, circulating or in the course of round trip or any other operations in the well;- to find an optimal combination of circulation parameters (mud density, viscosity and yield point and pump delivery) ensuring required pressures in the borehole;- to be able to correct hydraulics program recommendations in the process of drilling according to actual circulating parameters. To improve the accuracy of estimations which is essential for hydraulics programs of this kind, it is necessary to determine more exactly the values of circulating mud rheological parameters at temperature /pressure conditions existing in the well and to take into account a number of factors which are generally neglected when pressures are estimated aiming at the optimization of drill bit hydraulics. These factors are: mud compressibility, drill pipe rotation, annular eccentricity and some others. To be able to evaluate the influence of the said factors on dynamics and kinematics of the annular flow it was necessary to obtain a theory solution of an inverse hydrodynamics problem concerning complex shear strain of the viscoplastic fluid in the annular channel with moving walls. Just the solution of not a direct but an inverse annular flow hydrodynamics problem constitutes a fundamentally new approach and a principal difference of the developed program from the known procedures. procedures. P. 203

Abstract A computer model of kicks in oil- and water-based muds has been developed as part of a contract from the UK Department of Energy. This work followed a study by the safety directorate of gas kicks taken while drilling deep, high pressure wells. The study highlighted the need for comprehensive mathematical modelling of kicks in oil-based muds incorporating the effects of gas solubility. A â??researchâ?? model developed jointly by Schlumberger Cambridge (SCR) and BP international, includes both oil- and water-based muds, pressure transient effects, the density and dispersion of gas-cut mud and new models for the migration of free gas. This paper describes the philosphy behind the code structure, the solution techniques and modes of operation. The capabilities of the simulator are summarised, the coding considerations discussed and comparisons between kicks in oil- and water-based muds are illustrated. Some details of the validation of the code against field and experimental data are given. The code structure is designed for maximum portability and is highly modular, allowing ease of maintenance and upgrade. The full mass and momentum equations are solved in a core algorithm using an implicit finite difference scheme. An equation of state developed by BP is used to describe the density of gas-cut drilling mud at conditions of up to 15,000 psi and 350 deg F. The temperature dependence of the drilling mud rheology and the rise velocity of gas bubbles in non-Newtonian fluids are described by new experimental work from SCR. Introduction The prevention and control of gas kicks is a major safety concern within the petroleum industry. The vast majority of kicks are brought under control but occasionally, due to incorrect procedures, faulty equipment or unexpected developments, a blowout occurs resulting in possible serious loss of life and damage to equipment. The gas entering the well-bore will displace drilling mud, producing an increase in pit level. However, if the mud used is oil-based the gas will dissolve in the mud and the volume change can be much reduced. This reduction can lead to an increase in detection time, which is one of the major problems associated with gas kicks in oil-based muds. The dissolved gas is carried up the well as a passive tracer until the bubble point is reached, at which point bubbles begin to form. The evolution of gas may occur very rapidly leading to a large increase in pit gain and give rise to a difficult well control problem. A number of potentially dangerous incidents have been reported while drilling deep, high pressure wells on the UK Continental Shelf. Some of the difficulties have been associated with the use of oil-based drilling muds. The UK Department of Energy expressed its concern by calling a seminar and discussion on the subject in June 1985 and then initiating a study of the drilling history of a selected sample of wells believed to be representative of the problem, [14]. As a result of these studies, the UK D.En [10] put out to tender a contract whose objective was to develop a state-of-the-art mathematical model to run on a mainframe computer for the investigation of well control, with particular emphasis on gas kicks in oil-based muds.

SPE Members Abstract Several gas-influx events have occurred during drilling with oil-based mud on the Gullfaks field. These have usually started when hard chalk stringers were penetrated, and abnormal pressurized gas bearing zones were drilled pressurized gas bearing zones were drilled into. These zones are often of low productivity and volume. Based on all available data from the influxes in wells I and II, the events have been analyzed. The analysis has helped to explain the development of the influx events, and also the control phases have been evaluated. Introduction During drilling operations on the Gullfaks field several hydrocarbon bearing zones with abnormal pressures have been penetrated. These zones are both shallow gas zones and deeper zones located in the eocene and paleocene sections. In general the deeper zones are captured by thin and hard chalklayers. Several gas influxes have been initiated from these zones. In this paper two actual cases from the wells I and II are presented and evaluated. Since oil based mud were used, the gas influx events had special characteristics related to the solution of gas in the mud. Based on all available data, both manually and computer recorded, the influxes have been analysed to determine, as exact as possible, the influx history from start of influx to the end of the control phase. Average gas rise and dispersion velocity is estimated. The data available for the control phase is analysed to evaluate the control procedure used. CASE HISTORY Available-data To be able to reconstruct the influx history, all available data was collected and systemized. Our database consisted of: – Daily drilling report – Operator – Daily drilling report – Drilling Contractor – Daily drilling fluid report – Mud company – Drilling parameter plots – Operator – Final well report – Mud logging company – Observations recorded on drillfloor – Conversations with drillers on duty Although the data logged during drilling were recorded versus time, all the final saved data are versus depth. This make the manually noted observations very valuable as a basis for analysing the actual situations. Influx 1 - Well I A tabulated summary of the influx development and the first part of the control phase is given in Table 1. The initial pit gain was detected by the driller. P. 531

Abstract While environmental constraints have lessened the desire or will to drill with oil-based muds on offshore wells, the fact remains that use of this type of drilling fluid is an economically sound practice on some wells. Some troublesome shales practice on some wells. Some troublesome shales make it the only way to reach the objective. Unfortunately, the decision to use oil-based mud comes when several attempts, with water-based muds, have failed. Lost hole, lost bottom hole assemblies, and lost MWD equipment result in extremely high well costs for the operator. When the decision to use oil-based muds does come, the drilling contractor's charge is get the rig to a zero discharge capability, arrange surface equipment, and develop procedures and training for the crews so that drilling with this system is at maximum safety and efficiency. The problem becomes more complex on floaters. The position of the blowout preventers and the difficulty of detecting small gas influxes have created the potential hazard of sudden unloading of the riser potential hazard of sudden unloading of the riser before diversion can be accomplished. Surface equipment on most rigs only provides for diverting the flow overboard or taking the surge of mud and gas into the shaker room. Both of these provisions leave much to be desired. provisions leave much to be desired. The drilling contractor can improve the situation by attacking the problem with a five step program. This program involves: program. This program involves: Preplanning with the operator to circulate suspected, but undetected gas influxes with positive control. Build a better flow line gas discharge system. Install a better firefighting system in the mud pit room. Install a bleeder valve arrangement to help vent the stack. Crew training on the procedures used in safely handling an oil mud drilling program. Introduction The use of oil-base mud (oil mud) on offshore wells, while still routine in some areas of the world, has become less than common practice in the Gulf of Mexico. Environmental considerations have lessened the desire or will to drill with oil mud. The use of oil mud, when drilling some troublesome water sensitive shales, is still an important consideration. These shales are sensitive to water base muds to a degree that make reaching the next casing point or objective "an expensive impossibility" On some wells determined operators make four or five attempts to reach the projected depth only to fail. The losses suffered from one multi-sidetracked well are four bottom-hole assemblies, including two sets of MWD tools, drill collars, stabilizers, mud motors, drill pipe and approximately 60 days. Permission was requested and granted from MMS to Permission was requested and granted from MMS to change to oil mud. The well was sidetracked again and drilled to total depth without further problems. The well plan had anticipated problems. The well plan had anticipated approximately 15 days to drill the interval. P. 715

Abstract Operator-requirements for cost effective technical solutions to borehole stability problems have historically been the impetus for new product and mud system development by the industry. Oil-based drilling fluids have long been recognized as a sound technical answer to problems encountered in deep-hot holes and, more recently, to stabilize boreholes with thick intervals of reactive clay formations. However, oil-based mud product development was slowing down until the introduction of low toxicity base oils in the late seventies created a need for new investigations. This innovation sparked a resurgence of oil mud research and development which has resulted in oil-based mud (OBM) systems being used routinely in many active drilling areas worldwide. Concerns for conservation, both economic and environmental, persist even after low toxicity oils have been accepted, based on field performance, as a suitable diesel replacement. These concerns are important to both the operator and contractor alike. Control of intangible costs related to mud expenditures is important to the operator, but rig modification and installation of auxiliary equipment to process the oil-based drilling fluid are equally important to both companies. This paper discusses a variety of equipment that is currently available for both onshore and offshore locations to improve oil-based drilling fluid conditioning, to aid oil recovery, to reduce pollution, and to maintain a safe working pollution, and to maintain a safe working environment. Minor modification of most of these techniques will allow their utilization on land, inland barge, platform, jack-up, semi or floating drilling units. Introduction Field development of drilling fluid research efforts has always been oriented toward improving the financial and, more recently, environmental objectives of drilling mad production operations. New product and total system development combined with improved application of mud engineering technology will continue to have a positive impact on this cost containment effort well into the late eighties. Future drilling activity in harsh environments will require improved drilling and logistics support equipment, better performance from consumables, and rigorous application of engineering principles to reduce the trouble time cost of each project. Selective application of oil-based muds has already contributed to this cost improvement on several recent projects in both the North Sea and the Gulf of projects in both the North Sea and the Gulf of Mexico. Replacement of diesel with low toxicity oils as a babe in these mud systems has provided an unexpected benefit of increased rates of penetration with no appreciable increase in total mud cost. This benefit would be lost very quickly if efforts to reduce surface losses, to eliminate contamination to improve treating methods and to ensure a safe work site are not successful. The following discussion will itemize various pi of equipment and techniques that can be utilized to handle these oil-based drilling fluids. Item selection for a specific application should be based upon the size and scope of that project. SURFACE EQUIPMENT Most drilling rigs require only slight modification of their rig floor equipment to be able to operate with oil-based muds WBML Mud buckets and pipe rack drains that can be directed back to the active system and textured (non-skid) metal surfaces around the rotary table are generally standard equipment on most land and offshore drilling units. Potable water wash-down systems have replaced high Potable water wash-down systems have replaced high pressure washers and the steam hose system on some pressure washers and the steam hose system on some rigs operating with low toxicity oil muds (LTOM), even in cold weather environments. This is due to the improved surface tension characteristics of the base oil. p. 129

Abstract A computer simulation study of blowouts was made using a program written earlier. This study shows the predicted effects of various sized kicks on a given wellbore configuration and studies the major variables affecting kick severity in both water- and oil-based muds. The variables include reservoir variations (pressure, permeability porosity, temperature) and pumping rate at the porosity, temperature) and pumping rate at the surface. Results are shown for the effects of each of these variables on an uncontrolled kick. The present program does not include control procedures present program does not include control procedures but does include some examples of flow through a choke. It was intended to show what might happen if no control procedures were initiated and to study the lower limits of kick detectability. Practices are suggested that should make earlier detection of a kick possible so that conventional kill procedures will be more effective. Blowout simulations suggest that pit gain is the most reliable indicator of a kick. It is recommended that pit level measurement systems, capable of detecting a pit gain of less than 5.0 barrels in the entire active mud system, be developed and be used where high pressure kicks are common. Introduction A gas or gas-condensate kick represents one of the most dangerous situations in the drilling of an oil well. The fluid entering the wellbore is subject to expansion as it moves up the wellbore against a reducing pressure gradient. The type of mud used can radically affect this expansion. As shown in an earlier paper, gas dissolving in oil-based muds changes the surface effects of a kick. The earlier paper described in detail the effects of solubilization and discussed the phenomena involved. That paper also described a blowout simulation program that had been written as a part of that study. program that had been written as a part of that study. The present paper makes use of that program with some extensions to simulate the effects of changing pump rates and the effects of the reservoir on kick pump rates and the effects of the reservoir on kick severity. The present study was undertaken to help the engineer visualize the phenomena that produce the surface effects that he must deal with to successfully kill a well. Please bear in mind while reading this document that the results presented are simulations using a mathematical model. We have attempted to account for the important variables as we gee them. Other unrecognized variables may modify the results significantly. It is hoped that our work will stimulate a new round of development in well control methods. BLOWOUT SIMULATION MODEL The equations and theories used in the simulation model are described in detail in our earlier paper. The discussion here is limited to the paper. The discussion here is limited to the concepts involved. A simulation of the wellbore dynamics requires several parts: a reservoir model, an estimate of the bottomhole pressure, a description of multiphase flow in the annulus, friction pressure estimates, and gas interaction with pressure estimates, and gas interaction with drilling fluids. The reservoir model chosen was a time dependent radial flow equation that allows the variation of permeability, porosity, bottomhole temperature, permeability, porosity, bottomhole temperature, formation thickness, and formation pressure. This model gives an acceptable simulation of the initial drawdown of a reservoir. The equivalent bottomhole pressure while circulating must be calculated when no gas is present and when gas is migrating in the annulus. The uncontaminated mud above the gas-contaminated mixture in the annulus was simulated using a friction pressure model developed by Randall and Anderson. The hydrostatic head with gas present was calculated using a holdup correlation developed for a multiphase pressure drop model. The annular volume was divided into numerous segments that were assumed to be uniform in composition. P. 149