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Introduction The evaluation of certain reservoir properties, such as porosity and fluid saturation, from electrical well surveys has been widely accepted in petroleum engineering. Various investigators have established relationships between these properties and certain parameters which affect the response of the electrical log. Among these are the resistivities of the mud, its filtrate, and its filter cake. In 1949, Patnode established a relationship between the resistivities of the mud and filtrate. The well logging service companies have contributed relationships for the mud-mud cake resistivities. These have been valuable since it was the practice to measure only resistivity of mud at the well site. During the mid–1940's the industry began drilling wells with oil-emulsion drilling fluids. These were conventional aqueous muds with a dispersed oil phase. Since 1950, oil-emulsion muds have been used on an increasing number of wells each year. However, the practice of measuring only the resistivity of the mud at the well site has continued, and the mud filtrate and mud cake resistivities have been determined by the above-mentioned relationships. Service companies are now equipped to measure all three resistivities at the well site. An investigation was conducted on the resistivities of oil-emulsion muds, mud filtrates, and mud cakes to determine if these values conformed to the relationships for aqueous muds. Types of Muds Fifty-one oil-emulsion mud samples were prepared in the laboratory following a standard manual published by a leading mud company. The diesel oil in the samples varied from 5 to 50 per cent, the majority of the samples being in the 10 per cent region. The basic aqueous mud types which were converted to oil-emulsion muds were commercial clay and bentonite muds, low pH and high pH, caustic-quebracho treated muds, and lime treated muds. The emulsions were stabilized by dispersed solids, lignins, lignosulfonates, sodium carboxymethyl cellulose, or sulfonated petrolatum. It is worthy of note that after a quiescent period of two weeks at room temperature all samples, regardless of emulsifying agent, remained stable. The make-up water for the muds was from the laboratory tap. Resistivities were varied by the addition of table salt to the water. A range of mud resistivities from 0.44 to 3.9 ohm-m was obtained in this way.

Original SPE manuscript received for review June 10, 1995. Revised manuscript received July 24, 1995. Paper peer approved July 26, 1995. Paper (SPE 29370) first presented at the 1995 SPE/IADC Drilling Conference held in Amsterdam, Feb. 28-March 2. Journal of Petroleum Technology, October 1995. Summary Far too often, the basis for selection of a mud system is the "latest, greatest" technology or personal preference rather than sound cost-effective analysis. The use of risk-vs.-cost decision analysis improves mud selection and makes it a proper business decision. Several mud systems usually are available to drill a well and, with good decision analysis, the cost-effectiveness of each alternative becomes apparent. The Nigerian Natl. Petroleum Corp. and Mobil Producing Nigeria (MPN) recently began development of the Oso field, a condensate development funded by the World Bank. The budget authorized $187 million for development drilling of 19 wells and completion of 21 wells. Early drilling was very troublesome owing to wellbore instability, lost circulation, and stuck pipe. In addition, the mud cost was excessive because of high dilution rates and expensive mud products (especially barite, which was 50% of the final mud cost). This paper describes how the drilling team used structured decision analysis to evaluate and select the best mud system for the project. First, Monte Carlo simulations forecast the range of possible results with each alternative. The simulations provided most-likely values for the variables in the decision tree, including reasonable ranges for sensitivity analyses. This paper presents and discusses the simulations, the decision tree, and the sensitivity analyses. The analysis compares several factors in six mud systems, including cost-per-barrel; dilution; trip time; rate of penetration (ROP); stuck pipe, lost-circulation, wellbore-stability, torque-and-drag, filter-cake, and carbonate problems; and environmental concerns. The analysis used variables based on actual data whenever possible. The results indicated that, in spite of necessary rig modifications and increased risk of lost circulation, a mineral-oil-based mud was the best choice. Before introduction of the mineral-oil-based mud, a steady improvement had occurred in drilling performance, which improved dramatically after this mud was introduced. During the project, 21 wells were completed and 22 development wells were drilled (three more than originally planned). Total cost was $176 million, $28 million under the original budget and $11 million under the final budget. This paper presents field results that show the improvement in well, mud, and coring costs; average ROP; and trouble time. Through sound application of decision analysis, selection of the mud system becomes a sound business decision. Introduction The Oso field lies 15 miles off the southeastern coast of Nigeria in 50 ft of water. Although the field was discovered in 1967, development drilling did not begin until mid-1991. Initially, the wells were troublesome and very costly, and budget overruns to the World Bank funding seemed likely. It became apparent that any improvement in drilling performance would require significant changes. Mud-related problems were apparent. There was high incidence of stuck pipe, high torque and drag, filter-cake buildup, and borehole instability. Wiper trips were nightmarish, with the drill string virtually being stuck on every connection when tripping from total depth (TD). In addition, the mud cost was excessive. The drilling team felt that a different mud system was necessary for significant reduction of mud-related problems, but was undecided about which system. The team members (MPN Drilling Operations, MPN Drilling Engineering, MPN Fluids Group, the rig contractors, and the mud companies) made several recommendations primarily on the basis of prior experience, product availability, or personal preference. The choice of the mud system had to be a good business decision, the one that added the most value to the project. The objective was not to reduce torque and drag, eliminate stuck pipe, avoid lost circulation, improve wellbore stability, or reduce the mud bill. The objectives were to minimize drilling cost and to maximize the value of the project. In fact, reducing the drilling cost was only an objective in so far as it also resulted in increased value for the Oso project. Structured decision analysis would help to ensure that nonbusiness-related issues and personal bias did not affect the choice and that the team remained focused on the company goal: maximum value for the project. Mobil commonly uses forecasting, risk analysis, and decision trees on such problems as whether to drill, well-location selection, well configuration, and to fish or to sidetrack. However, the company had never used these decision techniques to select a mud system. Mobil and the drilling fluids companies had the considerable data required to predict the performance of the recommended mud systems, and MPN had the software required to perform the risk analysis and to create the decision tree. The drilling team decided to apply these decision-analysis techniques to the mud selection for Oso. This paper describes how the team applied forecasting, risk analysis, and decision trees to selection of a cost-effective mud system. The analysis compares and evaluates alternative mud systems by use of historical data to establish probabilities of success and then constructs the decision tree with these probabilities. The paper also presents field results with the selected mud system. Discussion The first 13 wells for the Oso development used a potassium-lignite drilling fluid. This system proved costly, not only from the drilling-fluid costs but also from the trouble time associated with mud-related problems. Wellbore-stability models indicated that additional mud density would help prevent the shale problems. However, barite costs and dilution requirements were high, and lost circulation and differentially stuck pipe and logging tools, problems resulting from the use of higher mud weights, occurred frequently. Torque and drag were at the limits of the mechanical equipment, and filter-cake buildup across the production sands made running casing difficult. At best, running casing usually required washing to bottom. On occasion, the pipe would stick off bottom. From TD, to short trip to the shoe with only about 5,000 ft of open hole normally required 24 hours. Also, carbonate contamination caused excessive use of chemicals to control viscosity and fluid loss. MPN initiated a study to select a different mud system. The team members made recommendations. Several mud systems were available that would "do the job." Without a structured method of decision making, the company faced the task of trying different mud systems on successive wells and comparing the results. This haphazard approach could prove to be very expensive. Mobil has a large database of mud systems used in Nigeria and worldwide, and the Drilling Div. decided that a structured analysis of the decision, with information from this large mud database, would be a valuable aid in selecting the best system for the Oso project - the system that would maximize expected value of the project. Judgment calls, made with structured thought processes and a large database, are significantly better than intuition and personal experience and bias. The decision analysis included six alternative mud systems:low lime,potassium lignite,polyanionic cellulose (PAC)/lime,partially hydrolyzed polyacrylamide (PHPA),PHPA/glycol, andmineral-oil mud. The first step was to define the risks and costs associated with each mud system. P. 909

Summary A multitude of new drilling-fluid products, systems, and treatment processes have been developed recently in response to increasingly stringent environmental regulations. Many fluid additives and systems that once played a major role in the drilling industry are in little use today or are no longer available. New water-based mud systems are approaching the performance levels typical of conventional oil-based muds, levels largely achieved by new synthetic-based fluids. However, these new drilling fluids do not have the adverse environmental impact associated with oil-based systems when waste fluids and cuttings are discarded. Introduction Drilling-fluid technology has undergone significant changes in the past 5 to 10 years. Much of the change has been in response to new demands placed by regulatory agencies on drilling-fluid disposal from offshore locations. The response has led to increased use of polymer drilling fluids, the application of glycol and glycerol additives, and the development of synthetic-based muds, water-based spotting fluids, and many other new additives. The tried-and-true drilling fluids of the 1970's and early 1980's now play a much smaller role in the industry. The successful response to changing environmental regulations resulted primarily from the efforts of service, oil, and chemical company laboratories working independently toward a common goal. The event that had the most profound effect on drilling-fluid technology in the U.S. occurred in 1986. On July 2, 1986, regulations took effect that placed a limit on the toxicity of water-based drilling fluids being discharged into the Gulf of Mexico. Until mid-1986, operators in the Gulf of Mexico were allowed to discharge water-based drilling fluids and cuttings that did not contain diesel oil or "free oil." The presence of free oil was defined as a visible sheen on the receiving waters. After the early 1980's and before the toxicity limitations, water-based muds could be discharged if they could be assigned to one of eight authorized (generic) mud systems and the composition held within prescribed limits. Oil-based drilling fluids and cuttings could not be discharged, particularly if the oil-based mud was formulated with diesel oil. Equally important to the changing environmental requirements are the performance demands dictated by the new types of wells being drilled- e. g., deepwater, extended-reach, horizontal, and slim-hole wells. Fluid requirements for such wells have also resulted in new systems and additives. Wells are being drilled at higher penetration rates over longer, higher-angle intervals without bit trips than in the past owing to improvements in rig, bit, drillstring, and directional technologies. These improvements must be met by enhanced drilling-fluid performance. Most of the changes in drilling-fluid technology have taken place at a time of low oil prices and reduced industry employment. In July 1986, oil prices dropped below $10/bbl from almost $28/bbl just 6 months earlier. This intensified the industry downsizing that had started in the early 1980's. While some research projects were terminated or delayed as resources were reduced, drilling-fluid technology continued to advance, and the performance of today's drilling fluids far exceeds those of just a few years ago.

Summary. This paper discusses testing of horizontal technology for use in the highly fractured Giddings field. Three short- and seven medium-radius wells were drilled successfully in the Austin Chalk formation. The paper discusses well plans, bottomhole assemblies, trajectory control, telemetry, mud systems, hydraulics, hole cleaning, casing design, cementing, problems encountered, formation evaluation, completions, and reservoir response. Introduction The Austin Chalk formation of the Giddings field in central Texas (Fig. 1) is an Upper Cretaceous fractured limestone oil and gas reservoir that was developed in the late 1970's and early 1980's. Initial development was accelerated by the explosive oil prices of the time and by the earlier development of the Pearsall field. Although the Giddings field was discovered in 1961, its potential was not evident until 1973, when re-entry into the Giddings No. 1 flowed 300 BOPD. Field development began in 1976 and accelerated rapidly. Because of the field's highly variable natural fracture system, initial performance of vertical wells ranged from highly prolific to exceptionally poor. Field development declined rapidly after 1982, partly because of failing oil prices. By 1984, reservoir studies and stimulation analyses had revealed why recovery efficiency from existing vertical wells remained low: the vertical wellbores were linked to only one natural fracture system, leaving unpenetrated fracture systems and matrices poorly drained. Instead of drilling infill vertical wells to drain the reservoir, we tested horizontal drilling and completion technology to determine whether multiple natural fracture systems could be linked to a single wellbore. Since 1985, a total horizontal displacement of 14,500 ft has been drilled within the pay. The longest horizontal displacement, pay. The longest horizontal displacement, 2,200 ft, was drilled within a 30-ft target. Geology and Background The Austin Chalk produces along a trend 10 to 25 miles wide and 250 miles long from Mexico to Brazos County, TX, with scattered production in east Texas. The most prolific area to date is the Giddings field, covering 1,200 sq miles in Burleson, Lee, Fayette, and Washington counties. Structural strike in the Giddings field is northeast, with the productive portion of the field ranging from 6,500 to portion of the field ranging from 6,500 to 12,000 ft. Porosity ranges from 3 to 12%, with very low matrix permeability (less than 0.1 md). Net pay thickness ranges from 10 to 240 ft. Reservoir development in the Austin Chalk is almost wholly the result of fracturing, creating a permeability system of near-vertical fractures that run parallel to structural strike (i.e., northeast/southwest). Because these linear fracture systems, which connect the tight matrix with a wellbore, are isolated flow channels, only limited areas can be drained by a vertical wellbore. Horizontal drilling, however, connects multiple vertical fracture systems with a single perpendicular wellbore to drain a larger area perpendicular wellbore to drain a larger area at higher producing rates. All 10 horizontal wells targeted the bottom portion of the Austin Chalk because of its abundant fractures, greater oil saturation, and proximity to the Eagleford, which also may be a major source-rock contributor of hydrocarbons. Definitions for Horizontal Wells The popularity of horizontal drilling during the last few years has led to use of the term "horizontal drilling" for many conventional directional-drilling operations, river crossings, extended-reach drilling, and other directional applications. We think horizontal drilling should be defined as a drilling and completion technique in which the wellbore remains in a high-angle trajectory roughly parallel to the formation, thereby exposing significantly more pay to production than would be exposed by a vertical production than would be exposed by a vertical wellbore. Many of the more recently developed, aggressive curve-building techniques are not actually horizontal drilling unless the lateral wellbore remains in the target for a distance 10 or more times the thickness of the net pay. In many reservoirs, a lateral length 20 to 50 times the thickness is necessary to make horizontal drilling economically viable. JPT P. 773

Summary The use of a new and different low-toxicity, low-pollutant oil-mud base fluid is presented. This low-polynuclear-aromatic (LPNA) oil differs from most other white mineral oils in that it is composed of 99+ % cyclic and branched paraffins with an average carbon number of C13. It contains less than 0.1 % aromatics and less than 1 % n-paraffins. This base oil composition provides for some interesting oil mud properties, which are discussed. Toxicity studies by an independent laboratory show the LPNA oil and the oil-mud cuttings to be substantially less toxic than diesel oil and the diesel-mud cuttings, respectively. Oil retention on the cuttings was shown to he less than for a comparable diesel mud. Laboratory formulation data, toxicity testing, and field test results are presented and discussed. These studies show the LPNA-oil-mud system to be an acceptable substitute for diesel mud systems and especially applicable to environmentally sensitive drilling locations. Introduction Advantages of Oil-Based Muds In recent years, there has been a marked increase in the use of oil-based drilling fluids. The widespread usage of these fluids has come about as a result of the proved advantages of oil-based muds over water-based muds in many difficult drilling situations. Oil-based drilling fluids have many favorable characteristics, including:excellent thermal stability for drilling deep hot holes;inherent protection against acid gases (e.g., CO2 and H2S) and corrosion caused by the presence of the continuous oil phase and the alkalinity control reagent (lime);capability of drilling water soluble formations (e.g., salt, complex salts, gypsum, and anhydrite) with little or no hole washout problems;improved lubricity, which aids in drilling deviated holes and reduces occurrences of "stuck pipe" problems;protection of producing formations from water intrusion, protection of producing formations from water intrusion, thereby eliminating clay swelling, which could result in reduced permeability of the pay zone; andability to drill thick, water-sensitive shale sections with relative ease, thus providing for gauge-hole drilling. This last characteristic is accomplished through the design of the internal brine phase of the oil-based mud. Such a system can be structured to provide an osmotic dehydration of the formation shale, thus preventing hole sloughing and providing for the stabilization of the borehole. providing for the stabilization of the borehole. When considering a drilling fluid program for a given well, the economics of a mud system is certainly of prime importance. In many cases, oil muds are not considered (although the drilling conditions warrant their use) because of their high initial mud cost (two to four times greater than most water-based muds). However, if the overall drilling costs are considered, the costs accompanying the use of an oil mud are usually comparable with or less than those of a water-based fluid. This is because most of the drilling problems are eliminated, resulting in substantial time savings. In addition, oil muds can be reused or resold following the drilling operation. Environmental Concerns The major concern in the use of oil-based drilling fluids revolves around their potential for adverse environmental impact, especially in potential for adverse environmental impact, especially in ecologically sensitive areas (e.g., active reefs or wetlands). In U.S. gulf coast drilling, current environmental regulations prohibit discharge to the sea of oil-based muds or any oil-mud cuttings that will cause a sheen. This is covered in Sec. 311 of the U.S. Federal Water Pollution Control Act (Clean Water Act) where Pollution Control Act (Clean Water Act) where Environmental Protection Agency (EPA) regulations disallow the discharge of any oil that will "cause a sheen or film or discoloration of surface water or adjoining shorelines - … "(In the context of this paper, the lack of a sheen, film, or surface discoloration on the water is referred to as "nonpolluting.") Sec. 402 of the Clean Water Act also regulates the discharge of pollutants by National Pollution Discharge Elimination System (NPDES) permits. Such permits allow for the discharge of drill cuttings, provided no oil is released that will cause a sheen or discoloration of the surface water. Whole oil mud discharges are prohibited in every case. Interim environmental regulations by the U.K. Dept. of Agriculture and Fisheries allow for the discharge of oil-based drill cuttings in North Sea waters, provided that the cuttings have less than 5 wt% oil (measured by retort) if diesel oil is used as the base fluid, or less than 15 wt% oil if a mineral oil is used as the oil-mud base fluid. Again, no whole mud discharge is permitted in any case. Oil Mud Components. JPT p. 137

Summary Sound well planning and carefully chosen drilling systems have proved successful in completing two high-angle holes through troublesome formations in the Gippsland basin offshore Victoria, Australia. Located about 60 miles [97 km] out in the Bass Strait, Mackerel Wells A-14 and A-16 set new records for being the longest horizontal displacement wells drilled to an angle of up to 72 degrees [1.26 rad] to the vertical. Both wells are producing oil from a previously fault-isolated reservoir southwest of the platform. The use of invert oil emulsion and aluminum drillpipe represented a significant change from normal Bass Strait drilling operations. This, in conjunction with tightly controlled angle buildup and directional control, ensured that the projected well paths were achieved. Completion procedures peculiar to highly deviated holes also were employed to bring the wells on stream successfully. A "controlled activity" oil-continuous mud system was chosen to alleviate problems associated with shale hydration and to increase wellbore lubricity. Rig modifications for cuttings disposal were essential before mud systems could be changed over. In combination with aluminum drillpipe for reduced string weight (Well A-16), the oil mud helped minimize torque, drag, and wall-sticking tendencies. With similar drilling systems and well-planned completion techniques, the drilling of high-angle holes will play a vital role in deepwater development. Introduction As the petroleum industry heads toward regions of extreme water depth, techniques are being introduced to allow for production of marginal reserves in the latter phase of basin development. Until recently, a conventional platform technique lent itself to initial development in a new area but was not economically suited to reach outlying incremental reserves. Offshore Victoria (Fig. 1), areal coverage in the Bass Strait has been extended significantly by two innovations, increasing the recovery of hydrocarbon accumulations otherwise considered uneconomical for platform development. In 1979, the use of subsea completions was introduced for development purposes. In addition, the drilling of very highly deviated, directional wells from existing platforms was initiated and proved effective in producing outlying reservoirs previously beyond the reach of conventional techniques. In the early 1970's, the location of platforms (Fig. 2) was determined by use of a 45 to 50 degrees [0.79- to 0.87-rad] deviation-angle limit for directional wells. With each platform, this limit was gradually extended until a very significant change was accomplished by drilling two wells with an average deviation of 69 degrees [1.20 rad]. The successful completions of Well A-14 and the follow-up, Well A-16, drilled off the Mackerel Platform A, achieved a combination of extreme high angle together with deep TVD that to date had never been obtained. As a result, two world records were set for horizontal displacement drilling with this high angle and, more important, new oil is being produced from this previously fault-isolated reservoir. The success of these wells can be attributed in part to special drilling techniques that represented notable changes in ordinary Bass Strait operations. To investigate the need for these specialized systems, a brief history of mackerel Well A-14 is beneficial. Well A-14 originally goes back to the exploratory well, Mackerel A-4, drilled to evaluate the southern fault block associated with the known Mackerel reservoir (Fig. 3). While the well did encounter a significant oil column, the true geological structure of the fault block was uncertain. It is currently believed that either minimal or no communication exists between oil trapped by the fault block and oil contained in the main reservoir being drained by Platform A. The estimated recoverable reserves contained in the fault block was 39 million bbl [6.2 × 10 m3 1. Note that this recovery will be helped by a prolific waterdrive mechanism (Fig. 4) and that an expected two-thirds of the oil in Bass Strait reservoirs could be recovered because of this very strong natural water drive. Roughly speaking, that is about two times the worldwide average for the amount of recoverable oil contained within a reservoir. This water drive originates from deep subterranean water flowing away from the rain that has fallen on the hills near Sale, Victoria, and exerts continuous pressure on the Bass Strait reservoirs. Feasibility studies indicated that two methods could be employed to produce oil economically from the South Mackerel fault:through subsea completion. similar to that successfully installed on Cobia-2, orby drilling a very high-angle well from Mackerel Platform A. The directional well alternative was selected because of lower estimated initial and operating costs compared with the subsea completion. However, considerable risk of failure with the directional hole was recognized. The originally planned well path for Well A-14 represented the limits of directional drilling technology. JPT P. 241^

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 197423, “Cased-Hole Solution With Fast Neutrons and Sonic Reflective Waves in Tight Reservoirs,” by Ulises Bustos, Schlumberger, Carelis Moya, Equion Energia, and David Rose, SPE, Schlumberger, et al., prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. The complete paper presents a solution that assesses tight matrices and natural fractures at a level not previously achieved. At the tight-matrix level, advanced nuclear spectroscopy is carried out with a new pulsed-neutron device that achieves simultaneous time- and energy-domain measurements. A new resistivity- and salinity-independent methodology is presented for obtaining gas saturation by a measurement known as fast neutron cross section (FNXS), oil saturation from the total-organic-carbon log, mineral volumes solved from formation elemental concentrations from the energy domain, and porosity from the hydrogen index obtained from the spectroscopy time domain. Reservoir Challenges The reservoirs under analysis belong to the Colombian Pauto Complex field (Fig. 1). Wells drilled in the area have confirmed a staked structure architecture, in which three main thrust sheets can be differentiated: Miche, Guamalera, and Pauto Main. The present study was focused on the Mirador formation of the Pauto Complex, which can be described as a fluvial and shallow marine environment deposit system. The Mirador formation is divided into two zones by Middle Eocene unconformity and is almost totally composed of quartz grains and mainly cemented by silica and significant kaolinite content. An additional characteristic of this reservoir is the presence of natural fractures that contribute strongly to well productivity. The main production is from the Mirador formation and is characterized by highly complex heterogeneity and anisotropy because of a multidiagenetic process, the accumulated hydrocarbon of which is a gas rich in condensate with variations in composition. The reservoirs are located at average depths of approximately 17,000 ft in the eastern foothills of the Colombian Andes, a region characterized by high-tectonic-stress regimes and reservoirs intercalated with reactive shales. Those factors lead to challenging drilling conditions where the combination of oil-based-mud systems and small wellbore diameters (approximately 6 in.) at the target zones are the only way to minimize wellbore-stability problems. Data acquisition is also challenged because logging-while-drilling technologies are sometimes limited in small wellbores and openhole wireline logging is sometimes jeopardized by hostile hole conditions. Under these scenarios, the authors explored formation evaluation in cased-hole conditions with wireline-conveyed technologies for both matrix and natural-fracture systems. The described spectroscopy device is wireline-conveyed and consists of a nonradioactive/high-energy pulsed-neutron generator and a highly sensitive set of multidetectors equipped with advanced electronics for carrying out complex neutron-burst schemes for accurate gamma-ray spectral analysis. This achieves a broad mineral-spectrum analysis, highly significant for two key formation evaluation parameters, porosity and saturation. The porosity typically is derived from neutron measurements incorporated in the same tool, where the matrix components over the interest zones provided by this spectroscopy device ensure an accurate porosity computation. The technology provides gas saturation from a hydrogen-index-independent gas-detection device and the liquids/hydrocarbon fraction from the carbon measurement; other rock elements containing carbon also are considered for a precise saturation computation.

Three criteria are considered here: the transition from laminar to turbulent flow, the annular pressure loss due to circulation, and the average annular viscosity. Field methods of approximating the criteria are presented, as well as a discussion of the accuracy of the field calculations relative to computer-determined values. Introduction A method used successfully to plan drilling hydraulics for various types of mud systems is based on predictions of the ability of a fluid to clean the predictions of the ability of a fluid to clean the hole under conditions that cause neither liquid erosion nor high annular pressure loss. The prediction is based on a mathematical simulation of flow in prediction is based on a mathematical simulation of flow in the annulus between the rotating drillstring and the wall of the hole. The value of the prediction technique is directly related to the inclusion of the pertinent physical forces and laws in the mathematical pertinent physical forces and laws in the mathematical simulation. Savins showed the influence of rotating drillpipe and explained why the simulation must contain the calculation for a helical flow path rather than for simple axial flow. The methods of solving the helical flow equations, which require a computer, are documented, as are the experimental results. Values for annular performance criteria can be calculated using the computer program to determine the capabilities of different types of mud systems as a function of depth and flow rate. Combined with appropriate standards for optimum hydraulics, this method furnishes a sound basis for designing a circulating fluid. However, to extend the technique so that it may be used at the rig site to improve the analysis of hole problems requires methods to approximate the annular criteria calculations and devices to measure the mud's flow properties within the effective range of shear rates. Hole problems are frequently related to cuttings-carrying capacity, annular pressure drop, or liquid erosion. Since remedial action for these situations may be based on changes in mud viscosity of flow rate the expected results of these changes on each of the annular performance criteria should be evaluated. For example, the mud viscosity can be increased at all shear rates or only in some ranges of shear rate. Incorrect viscosity increase can lead to no improvement in hole-cleaning, to a greater loss in flowing pressure, or to a reduction in drilling rate. An pressure, or to a reduction in drilling rate. An increase in flow rate may develop turbulent flow, which increases both the slip velocity of the particles and the tendency towards fluid erosion. The purpose of this paper is to outline methods that can be used in the field to estimate the annular performance criteria and to describe an attachment to performance criteria and to describe an attachment to the Fann Model 34 VG Meter that permits the measurements necessary for the "duo-power" model used to simulate the liquid's stress/rate relation. Estimation of Performance Criteria The three criteria needed to evaluate annular performance are the laminar-turbulent transition, the performance are the laminar-turbulent transition, the annular pressure loss, and the average annular viscosity. A duo-power model is used to simulate the stress/rate relation of the liquid. Laminar helical flow calculations made by the computer were approximated by a combination of equations and graphs suitable for use in the field. Examples for 8 1/2 -in. and 12 1/4-in. holes are presented. JPT P. 167

Introduction Deeper drilling for oil is becoming more and more the rule rather than theexception. With deeper drilling come additional problems, perhaps the greatestbeing those brought on by the higher temperatures encountered down the hole, particularly in the Gulf Coast region of Texas and Louisiana. Temperaturegradients of the order of 1.8? to 2.0?F/100 ft are not unusual, and a gradientof 2.3?/100 ft is found in some areas of Texas. With a mean surface temperatureof 74?F, the following temperatures could be expected for a geothermal gradientof 2.0?F/100 ft: at 10,000 ft, 274?F, 12,000 ft, 314?F; 14,000 ft, 354?F; and16,000 ft, 394?F. Severe gelation of lime-base drilling fluid in wells thathave high bottom hole temperatures has become perhaps the most seriousdifficulty encountered in drilling under such conditions. Lime-base drilling fluids have been very successfully and widely used in thedrilling of wells in the Gulf Coast region because of their inherent stabilitytoward contaminants, their ability to suppress the swelling dispersion ofbentonitic shales, and their ease of maintenance. The gradual recognition, during the past few years, that these muds were, in themselves, the cause ofmany difficulties experienced in drilling has led to widespread efforts by thedrilling industry to determine the reasons for the failure of these mud systems and to develop mud systems capable of performingsatisfactorily under high-temperature conditions. Manifestations of High-Temperature Gelation It is generally possible to recognize the symptoms of high-temperaturegelation early enough that advance predictions can be made of seriousdifficulties in mud control, and the useful life of the drilling fluids can beextended by proper treatment. Following is a list of the manifestations ofhigh-temperature gelation:The drill string ‘takes weight’ while going in the hole after a trip. Inearly stages of high-temperature gelation it is possible to notice a slightreduction in drill string weight as the drill pipe is lowered near the bottomof the hole.Excessive pump pressure is required to start the circulationof drilling fluid at or near the bottom of the hole when going back to bottomafter a trip. T.P. 3638

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191776, “Successful Replacement of Conventional Organophilic Clay With Novel Polymer as Viscosifier and Filtration-Control Agent in Mineral-Oil-Based Drilling Fluids,” by Jing Zhou, SPE, Jairo Cortes, SPE, and Hisham Nasr-El-Din, SPE, Texas A&M University, prepared for the 2018 SPE Liquids-Rich Basins Conference—North America, Midland, Texas, USA, 5–6 September. The paper has not been peer reviewed. Organophilic clays mixed in oil-based drilling fluids (OBDFs) do not exhibit the same viscosity or suspension characteristics as they do in water-based drilling fluids because electrical interaction between particles is minimal, creating difficulty in building viscosity and gel strength under high-pressure and high-temperature (HP/HT) conditions. To address that problem, a new mineral-oil-based drilling fluid (MOBDF) was created by replacing the conventional organophilic clay with a novel polymer. Introduction Organophilic clays are widely used as primary viscosifiers for OBDFs and synthetic-based drilling fluids. These chemicals are prone to stratification in certain conditions, slow chemical-reaction times, high pressure spikes, and high equivalent circulating densities (ECDs). These mud systems also have temperature limitations. At high temperatures, thermal thinning and thermal degradation of their organophilic colloids permanently destroy their viscosification capabilities. At low temperatures, excessive and rapidly increasing viscosity is experienced. A need, therefore, exists for a fluid that produces higher gel strengths initially and maintains a relatively flat response to temperature throughout the complete temperature cycle of a drilling operation. Organophilic clays mixed in OBDFs do not exhibit the same viscosity or suspension characteristics as they do in water-based drilling fluids because electrical interaction between particles is minimal, creating difficulty in building viscosity and gel strength under HP/HT conditions. By switching from a standard OBDF containing organophilic-clay additives to a clay-free OBDF, the drilling operation will benefit from a drilling fluid capable of performing under the desired conditions planned, an overall reduction in logistics, a reduction in volume of fluid and material needed, higher rates of penetration because of lower ECDs, and the formation of a thin nondamaging filter cake that would eliminate the need for costly and time-consuming cleanup treatments. This paper studies the feasibility of developing an organophilic-clay-free drilling fluid capable of performing similarly to an already-tested drilling fluid containing organophilic-clay additives. Experimental Studies Two MOBDF formulas were used for the experiments. The first, MOBDF A, was prepared with a formula containing organophilic-clay additives. The second, a clay-free drilling fluid, MOBDF B, was prepared with a formula containing the replacement polymer viscosifier and filtration-control agent. Calcium carbonate was chosen as the weighting material for the two MOBDFs used for the analysis. High-permeability Indiana limestone cores with a thickness of 0.25 in. and a diameter of 2.5 in. were used to perform the filter-cake-formation and filtration analysis. Berea sandstone cores with a thickness of 6 in. and a diameter of 2.5 in. were used to perform the rock-wettability and emulsion-breakdown analysis. Both MOBDFs were heated to 150°F for 16 hours under hot rolling, and no phase separation was observed.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 139534, ’Preliminary Test Results of Nano-Based Drilling Fluids for Oil- and Gasfield Application,’ by M. Amanullah, SPE, Mohammad K. Al-Arfaj, and Ziad Al-Abdullatif, Saudi Aramco, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. The oil and gas industry is looking for small, chemically and thermally stable, biologically degradable, environmentally benign material to use in the design of smart fluids. Because of highly enhanced physiochemical, electrical, thermal, and hydrodynamic properties, nanomaterials are considered a promising material. Recently developed nano-based fluids were formulated to study the rheological and filtration properties and evaluate fluid suitability for oil- and gasfield application. Initial test results indicate that the newly developed nano-based drilling mud produces suitable high- and low-end rheological properties. Introduction Water- or oil-based drilling fluid is the first foreign fluid that contacts the reservoir zone of a borehole. Most muds contain particles that are part of the mud formulation. These desirable mud solids can cause severe formation damage in the presence of a poor quality mudcake. Moreover, the cutting debris generated while drilling may produce enough microsized and colloidal particles to cause severe formation damage if a poor quality mudcake is deposited on the borehole wall. Hence, drilling muds that are unable to form a well-dispersed, tight, thin, plaster-like external mudcake on the borehole wall can cause serious formation damage because of the formation of an internal mudcake. Spurt loss associated with most of the mud systems is one of the notorious sources of solid-particle and particulate invasion in the vicinity of the wellbore. Fine particles coming into the drilling mud as a part of drill solids may also cause severe formation damage if the mudcake formed on the borehole wall is poorly dispersed, is very thick because of particle flocculation, and has highly porous fabric because of loose-fabric formation by the flocs, aggregates, and particles. The thickness of the deposited mudcake is also a critical factor in many drilling and reservoir-engineering problems. Muds producing soft and thick cakes increase the potential of differential sticking and, thus, are not desirable for geological formations highly prone to differential sticking.

Original SPE manuscript received for review May 15, 1995. Paper peer approved June 14, 1995. Paper (SPE 30116) first presented at the 1995 SPE European Formation Damage Conference held in The Hague, The Netherlands, May 15-16. Journal of Petroleum Technology, September 1995. Summary Openhole completions with prepacked screens are increasingly the completion of choice for horizontal wells requiring sand control. For maximum productivity from these wells, preventing mud damage to the formation and the screens or removing it before bringing the well onto production is vital. A common industry approach to this problem is to displace the drilling mud to an aqueous clear fluid before production, typically followed by a breaker fluid. This paper details an alternative approach: bringing the well on without cleanup. The paper outlines the decision-making process, shows how the drill-in-fluid and cleanup operations are designed, explains how laboratory testing can be used to support the design philosophy, and highlights that quality control of the mud system while drilling is critical to the success of such a well. Case histories in two very different reservoirs are presented that illustrate the success of this approach. Introduction The use of high-angle and horizontal wells is increasingly widespread, primarily because of the enhanced productivity they provide from many types of reservoirs. These wells often use uncemented predrilled liner completions or, for wells requiring sand control, prepacked screens. Because the wells are not perforated, mud damage cannot be bypassed. Therefore, to maximize productivity, preventing or removing mud damage to the formation and the screens before bringing the well onto production is vital. Mud damage can affect well productivity in a number of ways.Formation damage to the rock matrix owing to mud-filtrate invasion. This is almost impossible to remove but can be minimized by appropriate mud design.Internal and external mud filter cake. Oil or gas must be produced through the cake in uncemented completions. Considerable pressure drop may be required to initiate production.Plugging of sand-control screens by insoluble drilling solids or weighting material [mud or mud filter cake (from the wall of the hole)] is backflowed into the well. The most common industry approach to this problem is to displace water- or oil-based drilling mud to a clear aqueous fluid before production. In addition, a breaker system usually is placed in the open hole to remove or destabilize filter cake, thus reducing the drawdown required to initiate production. However, this approach can lead to problems on many wells.Breakers will often cause significant loss of fluid to the reservoir. This can result in formation damage from the breaker system itself and indirectly from subsequent kill pills. Severe losses also can compromise well control.Available pit space limits the number and volume of pills that can be pumped at many offshore locations.For certain oil-based muds (OBM's), displacement to completion brines can result in the formation of thick damaging sludges owing to poor displacement and fluid incompatibilities.Despite use of corrosion inhibitors, acid breakers can cause corrosion problems for metals commonly used in screen design, such as 316L stainless steel. Novel laboratory testing has lead to questioning many of the assumptions used in horizontal well cleanup. Depending on reservoir characteristics and inflow performance, the use of breakers is not al-ways necessary and can actually decrease well deliverability. Also, mud systems with fluid-loss control can be formulated that will flow through screens, eliminating the need to displace to clear fluids. On the basis of these findings, a simpler approach has been taken on two recent horizontal wells drilled with OBM systems. These wells were successfully brought on production with low-solids drilling fluid in the openhole section. Even though no conventional cleanup operation was carried out on these wells, comprehensive well-testing and production-logging programs showed that these wells were producing with minimal productivity impairment. In our opinion, this approach was not only operationally simpler but also carried a lower risk of productivity impairment for these wells. Cleanup Design System Design Parameters. Determining how the well should be completed and cleaned up requires an integrated understanding of a number of factors.Wellbore geometry (vertical, slanted, or horizontal well).Interaction between the drilling fluids and the formation to be completed.Reservoir quality (permeability, heterogeneity, etc.).Well/reservoir production management (sandface drawdowns available/permissible). For example, optimal completion of a horizontal well in a very-high-permeability oil sand where sandface drawdowns are on the order of a few psi will be very different from that of a slant well in a tight gas sand where drawdowns may be in the region of thousands of psi. Laboratory core testing must be integrated with inflow modeling and a clear definition of well objectives to quantify the effect of mud damage on well performance. Fluid-System Design. To determine whether the mud system proposed for use on a openhole completed well is likely to reduce well productivity, a number of different laboratory tests should be carried out. Reservoir-Condition Coreflood Test. A reservoir-condition core flood test is a standard way of assessing the level of damage that a mud filtrate might induce in reservoir core. In this test, the level of permanent formation damage can be determined by comparing the permeability of the core before and after its exposure to mud filtrate. Mud-filtrate damage levels ranging from 0% to 99% permeability reduction have been recorded. Note that damage levels of less than 50% have minimal effect on the productivity of horizontal wells. When interpreting the results from this type of experiment, care must be taken to ensure that the test really does simulate field events. Mudcake-Cleanup Test. A mudcake-cleanup test is a novel test that can be conducted to establish a "lift-off pressure." In this test, the core permeability at reservoir temperature and pressure is first established. A mud filter cake is then laid down on the face of the core. Finally kerosene is produced in the reverse direction, simulating production. The lift-off pressure, which can be attributed to the partial removal of internal and external cake required to allow hydrocarbon production, is calculated from the initial pressure peak (Fig. 1). Flow is maintained until a steady-state pressure is recorded from which a final (damaged-core) permeability is obtained. In well-consolidated reservoirs, this testing procedure is fairly representative of initial production conditions. P. 794

Summary Shale stability is still one of the most important problems faced during drilling. Until recently, stability problems were most often attributed to shale swelling; however, recent research shows that several mechanisms are involved and that their relative importance can be estimated. This paper presents a review of these mechanisms, including pore-pressure diffusion, plasticity, anisotropy, capillary effects, osmosis, and physicochemical alteration. Pore-pressure diffusion into the rock in the vicinity of the wellbore (transition from undrained to drained behavior) appears to be of major importance in these very-low-permeability rocks. Plasticity is discussed in terms of modeling. Compared with simple elastic models, modeling of plasticity can simulate the actual behavior of wellbore better. Rock anisotropy can influence failure either by its effect on stress redistribution or through rock-strength anisotropy. Analytical studies show that the second effect is more important. Capillary effects can significantly enhance the use of oil-based muds by effectively supporting the borehole wall. On the other hand, the same kind of effect between air and pore fluid can lead to misinterpretation of laboratory results on unsaturated outcrop material. Osmosis is a very controversial topic. Although industry publications do not give a clear idea of the extent of osmosis effects in shales, some guidelines can be established to compare it with other mechanisms. Physicochemical interaction between a shale and the drilling mud can lead to the dissolution of a mineralogical phase of the rock. Subsequent alteration of the rock cohesion can explain shale failure or dispersion. Thermal effects between cooling of the bottom part of the well and heating of the upper part can also be very significant. The behavior of different types of muds is discussed while taking these phenomena into consideration, and the practical use of rock-mechanics models is also addressed. Introduction For a long time, drilling through shales has been one of the most troublesome issues for the drilling industry. Despite the real progress achieved in the area of borehole stability, shale problems are still reported frequently (including long trip times to lost holes and sidetracks, the inability to log, or important washouts leading to poor log quality or poor cementations). Moreover, stability problems become more crucial as wells become deeper and boreholes more deviated. These wells, in which a limited number of casings and mud systems can be used (because of environmental problems with oil-based muds), result in open holes of increasing lengths, especially for larger diameters. Therefore, the open hole is exposed to drilling fluids for longer periods of time, which seriously impairs the resistance of borehole walls. The problems encountered in drilling in shales are caused by the large variety of rocks called shales and to the complexity of the mechanisms involved (mechanical, porosity-related, thermal, and physicochemical). Being able to characterize shales correctly and having a good knowledge of the mechanisms that can actually occur are key points in making an appropriate diagnosis and in solving or reducing problems associated with shales to acceptable levels. In this paper, several mechanisms or particular shale properties are discussed. Pore-pressure diffusion, plasticity, and anisotropy are the mechanical or poromechanical mechanisms, and capillary effects, alteration, and osmosis are the physicochemical mechanisms. Some other mechanisms are also briefly discussed, as well as effects of different mud types and use of rock-mechanics models.

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract Drilling high-pressure/high-temperature (HP/HT) exploration wells remains a challenge, despite years of experience acquired by the drilling/completion industry. Development wells have further expanded the envelope of performance of the technologies and procedures required to deliver production from HP/HT fields safely and economically. Now comes the time of drilling and completing infill wells, which paradoxically appear to be more difficult as depletion increases and the mud-weight window (MWW) diminishes. To overcome this problem, intense engineering work has been carried out to better understand the effect of the depletion on compaction and fracturing gradient, to design and qualify new drilling-mud systems combined with stress-caging techniques, and to prepare contingent solutions with the deployment of expandable- and drilling-liner technologies. Three infill wells have been drilled, completed, and put on production by Total in the Elgin/Franklin fields on the UK Continental Shelf. This success was achieved through severely depleted reservoirs—with depletion greater than 800 bar—and has enabled phased HP/HT developments and deep exploration beneath depleted horizons. Overview of the Elgin/Franklin Extreme-HP/HT Fields The Elgin/Franklin fields present an extreme combination of pressure and temperature (1,100-bar virgin pressure and 200°C, respectively) and remain the largest HP/HT gas/ condensate fields developed in the British sector of the North Sea. The fields are approximately 200 km northeast of Aberdeen in the Central Graben area. Following discovery and appraisal from 1985 to 1994, development started in 1996 with two unmanned wellhead platforms tied back to a central production facility. Eleven wells were drilled and put on stream, with deviations up to 50°, in an average drilling duration of 120 days. These wells were drilled before a predefined limit of depletion level had been reached, a level at which the MWW closes—calculated for Elgin/Franklin as 100 bar. First oil production occurred in 2001. Later, two satellite structures, Glenelg and West Franklin, were drilled and put on production through the existing installations in 2006 and 2007, respectively, (Fig. 1). The reservoirs consist of Jurassic sandstones buried at a depth exceeding 5300 m. The primary reservoir is the Fulmar, also called Franklin, sands. Reservoir fluids are gas/ condensate with a bottomhole pressure of 1100 bar and temperature of 190°C. The Fulmar reservoir is underlain by the Pentland reservoir with bottomhole conditions of 1150 bar and 200°C (Fig. 2). Despite the depth, the main reservoir shows significant porosity and permeability, allowing strong productivity. Up to 30% porosity and 1-darcy permeability are found in some Fulmar layers Individual wells in the field can produce up to 3.5×106 m3/d of gas with associated condensate. Surface production conditions are 860-bar wellhead shut-in pressure with an associated temperature of 180°C. The produced effluent contains 3 to 4% CO2 and 30 to 40 ppm H2S. Initially, field gas production reached 14.6×106 m3/d, with 24 000 m3/d of condensate. This combination explains the strong need for technology and in-depth engineering for these wells.

This article is a synopsis of paper SPE 59186, "The Application of New Generation CaCl2 Mud Systems in the Deepwater GOM," by D. Paul, SPE, Conoco; R. Mercer and J. Bruton, SPE, M-I LLC, originally presented at the 2000 IADC/SPE Drilling Conference, New Orleans, 23-25 February.

Summary The use of mobile, chemically enhanced centrifugation dewatering systems toprocess liquid waste from two deep exploratory wells in Kern County, CA, saved $136,900 in waste-disposal costs. Liquid waste in the wells was reduced by 45%. This paper tracks daily costs and chemical usage for each well to isolate keycost factors. Introduction The use of different types of dewatering technology to process effluent fromvarious industries has been well documented. others have reported on the use ofa centralized facility to process drilling waste transported from a number ofdrilling sites to the facility, hut the application of the technology at anactive drilling location has been limited by the complexity of dewatering. Theuse of the technology as an on-line addition to the rig's solids controlequipment has been suggested, but the results of such on-line processing havenot been extensively reported in the literature. This paper reviews the use ofone such dewatering paper reviews the use of one such dewatering technique, chemically enhanced centrifugation, at two active drilling locations. Chemically enhanced centrifugation uses chemical coagulants and flocculants toachieve fine-particle flocculation. The flocculated solids are then separatedfrom the waste stream with a high-speed centrifuge. This solids-separationtechnique differs from conventional "closed-loop" mud systems in oneimportant way: conventional closedloop systems rely on additionalsolidsprocessing equipment, such as "microclones" (small-diameterhydrocyclones), and traditional centrifuges to separate water and solids fromthe waste stream. Processing in this manner generally fails because theadditional solids-processing equipment cannot remove extremely fine particlesfrom the waste stream. When the particles from the waste stream. When therecovered water is returned to the mud system, fine solids are ala returned tothe mud. Continued reuse of the recovered water eventually results in afine-particle accumulation in the mud system that can be corrected only throughmassive dilution. Thus, the objective of waste-volume reduction is defeated or, at least, severely compromised. Chemically enhanced centrifugation, however, removes fine solids by treatment with chemical coagulants and flocculants. In July 1988, Arco Oil and Gas Co.'s Western Dist. began field testing of twodewatering units that used chemically enhanced centrifugation to process liquiddrilling waste. Both units were mobile in the sense that the component partscould be loaded onto two trailer trucks and transported to the drillinglocation for assembly. Both units were comparable in design and operation andwere furnished by the same service company. Before the units were selected, alist of checkpoints that were considered key to the successful operation ofsuch a unit was prepared (see Table 1). Available units were prepared (see Table 1). Available units were compared on the basis of a physical examinationfollowing this list. The unit with the best score was selected for the tests. Operational considerations limited the size of the reserve pit at bothfield-trial locations. The dewatering units were used to create aminimum-discharge (closed-loop) solids-control system. Because the cost ofliquid-waste disposal was $10.85/bbl, the plan was to send all the effluents tothe dewatering unit for processing. The recovered water would be returned asneeded to the mud system, and the solids separated by the centrifuge would bedischarged to the reserve pit. Because this recovered water was to be pit. Because this recovered water was to be reused in the mud system, asuspended-solids content of less than 500 mg/L and a residual-polymer contentof less than 0.1 lbm/bbl in the recovered water were dewatering goals. Thepurpose of these field trials was to assess the ability of the dewatering unitto achieve water-clarity goals for less than $10.85/bbl. This assessment wouldprovide one means of evaluating the economic viability of thisminimum-discharge solids-control system. Well Background Data The Mettler No. 1 was drilled in the Tejon (North) field, Kern County, CA. The dewatering test began July 26 and was completed Oct. 24. The dewateringunit was on location 96 days. Fig. 1 is a schematic of the well's hole size andcasing programs. The Arco-Texaco No. 801 was drilled in the Midway Sunsetfield, Kern County. The dewatering test began Aug. 18 and was completed Dec.20. Difficulty in setting cement plugs for directional control caused the timeplugs for directional control caused the time on location to be significantlylonger than planned (125 days). Fig. 2 is a schematic planned (125 days). Fig.2 is a schematic of the well's hole size and casing programs. JPT P. 730

Technology Focus This year marked the second year after completing my tenure as the deputy director of the University of Malaya (UM) Center of Innovation and Commercialization (UMCIC). UMCIC is the technology-transfer office in the UM, which is responsible for protecting UM’s inventions through intellectual-property registration such as patents and copyrights. Despite that, this year remained a busy year for me because it is time to restrategize my research and teaching endeavors. What I miss the most is that I am still not able to invest in more relaxing rounds of golf. As an academic lecturer and researcher in a Malaysian public university, I am often asked about the future of the upstream oil and gas industry. Most students are worried about the uncertainty of the industry. With unstable and low oil prices, which has led to massive job cuts for companies to stay afloat and remain relevant, many students are skeptical about pursuing petroleum engineering degrees. Not long ago, petroleum engineering bachelor’s degrees promised a bright and well-paid career. It used to bring in a six-figure salary. Unfortunately, now the luster has vanished with the slide in oil price. The rest, as they say, is history. Gail Tverberg, who is an actuary interested in finite world issues, has listed 10 reasons that a severe drop in oil price is a problem. At the top the list is, “If the price of oil is too low, it will simply be left in the ground.” Low oil prices translate to a rapid drop in production. They will also lead to a series of secondary effects such as debt defaults from deflation, loss of jobs, collapse of oil exporters, and loss of credit needed for exports. These will eventually lead to a rapid decline in oil production. In addition, secondary and tertiary recovery, specifically enhanced oil recovery (EOR), will be out of reach. I feel the industry needs to reinvent itself. It needs to think out of the box and make use of novel ideas and technology to maneuver during the challenging time. This year, the Federal Institute for Geosciences and Natural Resources, which is based in Germany, in its annual report, highlights a fascinating microbial EOR (MEOR) project that uses microorganisms in a conventionally depleted reservoir. It is a pilot reservoir project south of Beijing to determine “what microbes occur in the deposit and what metabolites they secrete (i.e., the substances that improve oil solubility).” The contemplated MEOR process marks a distinct departure from conventional wisdom. One of the major findings from the pilot project shows that microbes are normally undesirable intruders in oil reservoirs. They transform hydrocarbons into tar-like heavy fuel oil. In addition, oil producers ought to productively make use of something that is in the reservoir to begin with. It makes the tertiary-recovery process more environmentally friendly and, under specific conditions, perhaps even less costly. So, is petroleum engineering a sunset industry? If Tiger Woods can change his game, why not we? I hope you enjoyed and benefited from the selected and highlighted papers. There are other interesting papers on the recommended-reading list. For further reading, the OnePetro online library has additional papers. JPT Recommended additional reading at OnePetro: www.onepetro.org. IPTC 17801 Innovative Nonaqueous- Fluids Technology Improves Drilling Efficiency Significantly in Dealing With Divalent Complex Salt Formation Under HP/HT Conditions by Da Yin, PetroChina, et al. IPTC 17913 Successful Application of Customized Fluid Using Specialized Synthetic Polymer in High-Pressure Wells To Mitigate Differential-Sticking Problems by Minimizing Pore-Pressure Transmission by M.S. Al-Muhailan, KOC, et al. IPTC 18133 Stable Fracturing Fluids From Waste Water by Sarkis Kakadjian, Trican Well Service, et al. IPTC 18217 Successful Application of Innovative Technology Improves Lubricity of High-Performance Water-Based-Mud Systems in Challenging Environments by A. Maliardi, Eni, et al.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124854, ’Non-Retrievable Rotating Liner Drilling System Successfully Deployed To Overcome Challenging Highly Stressed Rubble Zone in a GOM Ultra-Deepwater Sub-Salt Application,’ by Jim Kunning and Yafei Wu, Anadarko Petroleum, and Ian J. Thomson, Larry Marshall, Derrick Daigle, SPE, Henry J. Mata, SPE, Robert Pena, Matt Hensgens, and Billy Eppley, Baker Hughes, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The full-length paper presents some of the geomechanical drilling hazards encountered in an ultradeepwater well in the Gulf of Mexico (GOM) Walker Ridge area, the effect of those hazards on the drilling operation, and the outcome of deployment of a nonretrievable rotating-liner drilling system. This drilling system, in conjunction with a specially designed liner drilling polycrystalline-diamond-compact (PDC) bit, enabled operators to drill through and isolate a challenging highly stressed rubble zone found adjacent to a problematic tar/bitumen layer. Introduction It is well known in the industry that, because of seismic acoustic-wave-velocity uncertainty across thick salt bodies and the high acoustic-wave-velocity contrast between salt and surrounding formations, the subsalt-environment characteristics and pressure regimes cannot be determined accurately by seismic models. As a consequence, unexpected events commonly are encountered, which include lost circulation, stuck pipe, highly stressed rocks, and tar zones below the salt body. Lost circulation and tar are among the most dreaded hazards in the subsalt drilling scenarios, mainly in exploration and appraisal wells, where only limited information about the area being drilled is available. When these hazards are found, drilling time and cost increase significantly. In many cases, these lead to unplanned sidetracks, suspension of operations, or even abandonment of the well. Casing/liner drilling traditionally has been used to solve localized drilling challenges related to wellbore instability while drilling through depleted reservoirs. Recent oilfield advances, including improved tubulars, and pipe handling, have proved that nonretrievable rotating-liner drilling is a viable cost-cutting option to overcome some of these new deepwater subsalt challenges. Nonretrievable Rotating-Liner Drilling System Advances in connections, rig technology, liner equipment, and mud systems have allowed liner drilling to move forward as a solution to challenges of drilling wells today, where conventional drilling may not be the best option. In deep- and ultradeepwater subsalt wells, it is proving more difficult to get a liner to bottom as a result of the challenging formations being drilled. The ability to wash, ream, or drill the liner string to depth always has been limited by the high circulating pressures that may be required to achieve such goals. Circulation rates have always been kept sufficiently low to avoid presetting the hanger or prereleasing the running tool during drilling operations. To overcome these issues, an improved design of a nonretrievable-liner drilling system that is easy to implement and practical in application was introduced.

Guest editorial When our industry talks about technology, the discussion quickly moves to game changers and specific events in which a new widget does something new. These widgets are generally successful but are usually applied to relatively narrow applications. While I absolutely agree that such innovations are extraordinarily important to our industry, I believe that the humble, unheralded technology of process innovation will provide an equally important contribution to how we produce the next trillion barrels of oil. Our ability to take broad areas of technology and to reliably and rapidly customize very specific wellbore solutions will become increasingly important to our industry. In my job, I get to talk with clients all of the time, and I recently had the chance to listen to a group of successful operators discuss a resource play. The conversation quickly turned to how they planned to drill the asset, and I asked them about mud systems. They indicated that they planned to use oil mud, even though they believed water-based fluid would likely get the job done more efficiently. Why is this? The real reason was because the first well drilled successfully in this resource play was drilled with oil. This is an example of a situation where we are effectively doing what we have always done based on observation of a successful phenomenon. We can rely on observable phenomena as long as all of the "right" drilling parameters somehow remain consistent. I see the challenge less as one of new technology development, but rather as one more closely aligned with how we reliably apply mass customization of technology (in this case, chemistry) to reliably customize broad areas of science to specific wellbore challenges. Nevertheless, it is the rare drilling fluid system that is simply pulled off the shelf, sent to a location, and run successfully without some level of customization—one exception being possibly the soap stick, and even that was only under specific conditions. So, how do we effectively customize solutions on a large scale? First, we must understand why systems behave and perform the way they do at an elemental level. Next, we must execute stable processes that allow us to reliably investigate observed phenomena. Efficient customization of technology is increasingly important; additionally, complexity and drilling envelopes are pushed to the technical limits of the industry's current capability. By integrating engineering tools into the customization process, it becomes possible to more efficiently and reliably distill broad technology systems down to a very specific and customized solution that maximizes the operator's wellbore value.

Summary A computer model has been developed to predict drillstring torque and drag, and a versatile rotary torque meter has been built to use in calibrating the model. The principle of the predictive model is that torque and drag forces in a directional wellbore are primarily caused by sliding friction. Sliding friction force is calculated by multiplying the sidewall contact force by a friction coefficient. Realistic sliding friction coefficients were determined from field data by using the same predictive computer model. These field data were gathered using novel torque and hookload indicators that are accurate, portable, and easily installed. Good agreement between friction coefficients calculated from different loads in the same well, as well as agreement between those for different wells, indicates the validity of the predictive drillstring model. Sliding friction is concluded to be the major source of torque and drag in directional wells. For water base mud systems, typical friction coefficients range from 0.25 to 0.40. Introduction Drill string drag is the incremental force required to move the pipe up or down in the hole; torque is the moment required to rotate the pipe. Drag forces usually are given relative to the string weight measured with the string rotating but not reciprocating. Measured from the rotating string weight, the pickup drag usually is slightly greater than the slack-off drag. The magnitudes of torque and drag are related in any particular well; high drag forces and excessive torque loads normally occur together. There are a number of causes for excessive torque and drag, including tight hole conditions, sloughing hole, key seats, differential sticking, cuttings buildup caused by poor hole cleaning, and sliding wellbore friction. With the exception of sliding friction, these causes are associated with problem conditions in the wellbore. Conversely, in wells with good hole conditions, the primary source of torque and drag is sliding friction. Torque and drag from any source tend to be more troublesome in directional holes. In very deep, highly deviated wells overcoming torque and drag can be critical to the successful well completion. The capability to predict frictional loads on drillpipe has two main benefits. First, deep, highly deviated wells can be planned to minimize torque and drag. Use of torque and drag as criteria to select the most appropriate well path will help ensure successful drilling operations to total depth. Second, more complete knowledge of drill string loading allows use of improved drill string design techniques. Drill string components can be chosen by using a systematic approach that considers the extra forces involved. Torque and Drag Prediction Technique Mathematical Model. A lumped-parameter model provides the basis for the prediction of torque and drag. Both torque and drag are assumed to be caused entirely by sliding friction forces that result from contact of the drill string with the wellbore. Other less important sources of torque and drag are not considered in this model. Two factors affect sliding wellbore friction-the normal contact force and the coefficient of friction between the contact surfaces. The product of these two factors represents the magnitude of the sliding friction force. The normal contact force between the pipe and hole wall depends on several factors. This paper considers only two contributions to nominal force-the effects of gravity on the pipe and the effects of tension acting through curvatures in the wellbore. These forces, and their contributions to normal force, are shown schematically in Fig. 1. Other factors such as pipe bending may contribute small normal forces but are not considered here. The sliding friction coefficient is the ratio of the friction force to the normal contact force. In reality, this value depends on specific contacting materials and on the degree of lubrication at various places in the wellbore. However, in this paper all these effects are expressed as a single characteristic friction coefficient representing average conditions in a particular wellbore. Determination of this lumped-parameter coefficient is fundamental to practical application of this model. Computer Calculations. The following paragraphs describe the calculation of torque and/or drag forces when the sliding friction coefficient is given. This calculation is made directly. The reverse calculation, where a friction coefficient is determined from given torque or drag data, is done by assuming a friction coefficient and iterating to match the data. In either case, drill string description and wellbore survey data are required.

This state-of-the-art paper discusses the reaction chemistry of commercial scavengers in water-base drilling fluids. Parameters that affect the reliability, of these materials for removing sulfides are emphasized. Practical problems of scavenger use, such as effects on mud performance, Practical problems of scavenger use, such as effects on mud performance, how to add the scavenger to mud, and rig-site monitoring methods, are considered. Introduction Excessive risks may be incurred from unquestioned reliance on sulfide scavengers during H2S drilling. Such risks can result from a lack of reliable information about how the scavenger should function and what factors (chemical and physical) control its behavior in a mud. A need for a summary about this often controversial subject prompted us to write this paper. We conclude that at prompted us to write this paper. We conclude that at present, no available commercial product approximates present, no available commercial product approximates die "ideal scavenger" defined here. Some products offer advantages, while some have major disadvantages because of characteristics of their chemical type and the mud's influential environment. Differences in chemical behavior in a mud are very important for safe H2S drilling, especially if a scavenger is being relied on greatly for H2S control and safety.We based the general scavenger chemistry presented here on the sulfide chemistry in the literature. Field experience with scavengers influenced aspects of this paper, but our specific laboratory studies and those of paper, but our specific laboratory studies and those of others are the major foundation for comments on factors influencing scavenger behavior in mud systems. Summary of Scavenger Application This summary of the practical aspects of using or not using a chemical as a sulfide scavenger in muds is based on discussions given later of background chemistry and test results. Only two types of scavengers are being marketed to the drilling industry currently:zinc-base chemicals andiron-oxide, Fe O. Copper compounds, although used in the past, are not considered satisfactory today because of drillpipe corrosion caused by reaction of copper ions with iron. No Scavenger A scavenger may not always be needed to control minor sulfides that result from drilling or similar small amounts of H2S entering a mud, although companies' policies may vary on this practice. A mud's natural scavenging capacity plus neutralization by mud alkalinity often are enough to control a minor amount of sulfides on a day-today basis. A change in operations, such as increasing mud weight, may reduce a small H2S influx to a negligible amount; then a scavenger is not needed. Where H2S influx could occur, it is important to measure the mud's soluble sulfide content frequently and quantitatively and to be prepared to add a scavenger if persistent filtrate sulfides appear. persistent filtrate sulfides appear. Zinc-Base Scavengers Two general types of zinc-base scavengers are now available;very slightly water-soluble inorganic compounds, the most common being basic zinc carbonate; andhighly water-soluble organic zinc chelate compounds. For mud applications over a broad pH range, zinc-base additives provide effective scavenging by a rapid and irreversible reaction with sulfides to form solid ZnS. JPT P. 787

Member SPE-AIME Abstract An automated particle size analyzer was successfully used in the laboratory, as well as in the field, for characterizing fine particles involved in drilling. Particle size distribution data particles involved in drilling. Particle size distribution data were obtained on weighting materials, clays and field mud samples in the range of a fraction of one to 192. Size analysis is a useful quality control tool to limit undesirable size fractions (e.g. less than 2 and greater than 74 ) in weighting materials. The median size measured for clay systems are found to represent the flocculation state of the clays in various salt environments. The measured size distributions of the solids in fresh unweighted water-based field muds are shown to be a good indicator of the operation of the solids removal equipment. The separation efficiencies of the 4" hydrocyclones were calculated from which the median separation size was found to be around 35 . An indication of the nature of the formation drilled was evident from the data. Introduction It is now commonly recognized in the oil industry that the solid particles involved in drilling have an immense influence on the economic and technical success of drilling and oil production. These particles are either added at the surface to prepare the mud, e.g., via weighting materials and clays or produced from drilling the formation. The understanding of the physical characteristics (size, shape and hardness) and chemical characteristics (surface charged nature) of these particles in the drilling fluid environment is crucial to the development of drilling fluid technology. The behavior of these solid particles in mud systems is manifested through differential pressure pipe sticking, clay/shale stability, dependence of rheology and penetration rate on solids, and efficient control of solids by certain solids removal equipment. Numerous papers and reports have been written since the late 1950's addressing adverse effects and the need for proper control of solids, solids analysis and performance of solids removal equipment. A few are listed in references. However, most of the results of the influences of solid particles are very qualitative or highly empirical. The understanding of drilling fluid systems can only advance by applying the knowledge of Particulate Technology and Colloid Science. Recently, Lauzon applied the techniques of Colloid Chemistry to characterize the chemical surface nature of drilling fluid solids. More recently, Roehl applied the concepts of Clay Colloid Chemistry to explain his experiments leading to a better understanding of shale stability. Complimentary to these, the industry needed a suitable technique to measure particle size distribution. The techniques used in the past were either very slow well suited to most drilling applications. This paper reports the extensive search undertaken to evaluate commercially available instruments to measure the particle size distribution of drilling fluid solids both for research and field use. Based on this evaluation, a laser diffraction device was purchased and tested both in the laboratory and the field. The purchased and tested both in the laboratory and the field. The particle size distributions in commercial weighting agents, clay particle size distributions in commercial weighting agents, clay suspensions and field drilling muds have been measured. From the field test data, separation performance of the solids removal equipment was evaluated. PARTICLE SIZE ANALYZER PARTICLE SIZE ANALYZERAn automated and portable French particle size analyzer was used in this study. The instrument is based on laser diffraction and it measures the size distribution of particles from a fraction of one to 192 p. This instrument would be referred to as the "Particle Size Analyzer" in this paper. The details of comparison of particle size analyzers and the results of analysis by those are provided in Appendix A. provided in Appendix A. In using the particle size analyzer, dilute suspension (500 m of the sample is made in a suitable medium (generally water). The suspension is agitated and continuously circulated through the measurement cell. P. 195

Tests on rigs in the Gulf of Alaska show that variations in surface mud volume measurements can range from 20 to 60 bbl (3.2 to 9.5 M), depending on vessel motions. These variations were reduced to acceptable levels with conventional equipment by placing single or pairs of sensors at or straddling the centroid of the mud surfaces in each pit. Introduction Pit-volume totalizers were developed initially for Pit-volume totalizers were developed initially for conventional land rigs with steel pits. On land operations, one float or sensor is placed in each pit downstream of the constant-volume shale shaker and treating pits. The signals from each sensor are combined to provide a measurement of the total mud volume in the portion of the active system downstream of the constant-level treating pits. On most pit-volume totalizer systems, the "total volume" also pit-volume totalizer systems, the "total volume" also is displayed on a gain/loss indicator that can be set manually at the zero position. The gain/loss indicator shows the number of barrels of mud that has been gained or lost since the signal was set at the zero position. The gain/loss indicator is equipped with position. The gain/loss indicator is equipped with limit switches that sound an alarm whenever a preset gain or loss limit has been exceeded. For well control operations these limits ideally would be set at the smallest practical gain or loss. Where reasonable care is exercised in providing a constant surface-volume mud system, the gain/loss limits can be set at acceptable values. In floating drilling operations, these limits must be increased by the magnitude of any variations in the pit-volume totalizer signal due to vessel motions.This paper reports measurements of the magnitude variation in pit-volume totalizer readings that result from vessel motions if one sensor is placed in each pit and describes an arrangement of sensors that virtually eliminates the volume variations caused by vessel motions. Theory Although the mud systems on floating rigs are subject to complex combinations of heave, pitch, roll, surge, and sway, the principal effect on pitvolume totalizer measurements appears to be caused pitvolume totalizer measurements appears to be caused by the pitch or roll motions. Fig. 1 is a schematic of a pit that shows how pitch or roll motion affects the pit that shows how pitch or roll motion affects the pit-volume totalizer measurements. The variation in pit-volume totalizer measurements. The variation in pit volume measurements caused by angular motions pit volume measurements caused by angular motions between the sensor and centroid of the pit can be calculated from the following relation. (1) For the pits studied, this relationship predicts a peak-to-peak range of volume measurements of more than peak-to-peak range of volume measurements of more than 50 bbl (7.9 M) for 3 degrees of pitch and roll motions.If the single sensor is placed at the centroid of the mud-pit surface, this relationship would predict no change in volume measurements caused by pitch or roll motions. It also is apparent that the average height of two sensors placed on a line through and equidistant from the centroid of the surface will eliminate the pitch and roll motion effects. Measurements Pit-volume totalizer (PVT) measurements were Pit-volume totalizer (PVT) measurements were obtained on a floating rig during a period when pitch and roll motions ranged from 1 to 3.5 degrees. Fig. 2 is a schematic of the pits and PVT sensor arrangements studied. Tables 1 and 2 list the measurements of the PVT signal range and the pitch and roll motion PVT signal range and the pitch and roll motion measurements. Test periods generally were limited to periods of 1 hour. periods of 1 hour. JPT P. 1497

Improved Formation Evaluation From Pressure and Conventional Cores Pressure and Conventional Cores Taken With Stable Foam-Bennett Ranch Unit (Wasson Field) Summary The analysis of pressure cores as well as conventional cores taken with stable foam from the San Andres formation in the Bennett Ranch Unit (BRU) of the Wasson field provided a better means of formation evaluation. The pressure-core data enabled correction of conventional-core pressure-core data enabled correction of conventional-core saturations to in-situ conditions. The results of this oil saturation adjustment method corroborate similar procedures cited in the literature. procedures cited in the literature. The pressure at the bit was controlled during the coring operation to minimize the possibility of altering core fluid saturation. Nitrate was used as a tracer material to measure filtrate invasion. The nitrate analyses of the core waters confirmed the lack of filtrate invasion. The foam pressure was adjusted during the coring operation as dictated by surface observations to maintain a balanced condition. Later calculations of these pressures provided a measure of the bottomhole pressure (BHP) provided a measure of the bottomhole pressure (BHP) variations in this thick formation that consists of variable-quality rock. These data provide a qualitative means to evaluate the volumes and paths of injection waters for estimates of the quantity of oil that may be contacted during tertiary recovery operations. Introduction Tertiary recovery operations require a large front-end investment in equipment and injectants. The prudent operator will preplan such operations to minimize risk and to optimize the chance for success. The Wasson field of the San Andres formation, located in west Texas is a target for tertiary CO2 recovery projects. Doscher and Wise report that Wasson field has the highest CO2 flooding potential of the 12 Grayburg/San Andres reservoirs listed in their paper. The BRU of the Wasson field may also be a candidate for a tertiary CO2 flood. A pilot area is under consideration. and Sun E and P Co. is pilot area is under consideration. and Sun E and P Co. is attempting to establish a credible data base before implementing such a project. Simplistic material balance approaches (i.e., residual oil equals original oil in place minus volume produced and shrinkage) do not provide the vertical and areal distributions of oil saturation. Log analysis likewise may not provide accurate hydrocarbon saturation information. provide accurate hydrocarbon saturation information. Fluid saturation data from conventional cores seldom yield oil values that are representative of true in-situ values. Pressure coring is a potential tool for providing insight Pressure coring is a potential tool for providing insight into hydrocarbon saturation and distribution. The pressure-core-barrel technique eliminates the reduction in pressure-core-barrel technique eliminates the reduction in oil saturation by gas expansion. However, misleading fluid saturation data may still result if the cores are flushed with drilling mud filtrate during the cutting of the cores. The ideal method is a core cut at balanced BHP conditions and brought to the surface without a reduction in the capture pressure. pressure. If the BHP exceeds the pressure that can be obtained with minimally weighted drilling fluids, a balanced drilling system may be designed. If the BHP is less than that from a normal water gradient, the use of most drilling-fluid systems will result in an overbalanced condition during coring, and pore space flushing will likely occur. Under these BHP conditions, stable foam can be a suitable coring fluid. The foam drilling-fluid system, unlike conventional mud systems, can be modified almost instantaneously to achieve the desired physical properties and pressures required to balance the BHP. pressures required to balance the BHP. Background The Wasson field is located in Gaines and Yoakum Counties, TX (Fig. 1) and encompasses some 68,500 acres [277 × 106 m2]. Production is from the San Andres dolomite at an average depth of 5,100 to 5,200 ft [1550 to 1600 m]. The producing interval customarily is divided into an upper "first porosity" zone and a deeper zone called "main pay." Discovered in 1936, the field was largely developed by 1941, and waterflood operations started in 1964. Initial oil in place was in excess of 1.5 × 109 bbl [240 × 106 m3]. As of 1974, the remaining reserves were estimated at more than 600 × 106 bbl [95 × 106 m3]. Ghauri and Swift et al. have provided descriptions of the geologic setting and Wasson field core data. The BRU is located in the northernmost tip of the Wasson field (Fig. 1) and contains more than 7,000 productive acres [30 × 106 m2]. The unit was formed in 1964 productive acres [30 × 106 m2]. The unit was formed in 1964 and was operated by the Texas Pacific Oil Co. Inc. Sun acquired the Lower 49 assets of Texas Pacific that included the unit in 1980. Water injection for unitized waterflooding operations began in 1965. As of March 1, 1979, the cumulative oil production was 38.9 × 106 bbl [6.2 × 106 m3]. production was 38.9 × 106 bbl [6.2 × 106 m3]. JPT P. 2203

Summary This paper is based on field experiences from two wells and laboratory experiments. Flow-induced abrasion is a considerable problem in the field when ilmenite is used as weight material. In general, field observations are confirmed by laboratory experiments. However, the abrasiveness is highly dependent on the particle size distribution, and experiments clearly show that the abrasiveness of ilmenite can be reduced to that of standard barite by removing the largest ilmenite particles. From our experimental results, we recommend that the size distribution of ilmenite contain fewer than 3% particles greater than 45 microns [45 ]. The use of ilmenite also demonstrated problems with dust. dispersion of ilmenite in water, air entrainment, and foaming, which, as found by laboratory investigations, can be eliminated by reducing the concentration of flotation chemicals. On the basis of field experience and subsequent laboratory studies, we conclude that ilmenite is well suited for use as weight material in drilling fluids since the presently observed disadvantages to a large extent can be diminished. Introduction The demand for high-quality barite as drilling fluid weight material is expected to be increasingly difficult to meet. In addition, the supply of barite is geographically limited, with high transportation costs as a consequence in many cases. Because of the expected shortage and possible cost savings, a research program based on Norwegian resources was initiated in Norway in 1975 to investigate possible alternative weight materials. In their study, Haaland et al. found iron-base materials such as ilmenite and hematite to have a good potential for use as weight material. The advantages of ilmenite and hematite as weight material include high specific gravity, solubility in acid, reaction with sour gases, similar or superior fluid properties compared with barite, and availability of large ore deposits. On the basis of this information, Statoil initiated two field evaluations and a subsequent laboratory study during 1979–81 to evaluate ilmenite as weight material. The purposes of the field evaluation were (1) to investigate the overall performance of ilmenite as weight material and (2) to identify problem areas that occur when ilmenite is used. The purposes of the laboratory study were (1) to find, and possibly eliminate, the cause of the observed hydrophobic character of the ilmenite used in the field tests, (2) to evaluate the abrasiveness of ilmenite when used as weight material, and (3) to develop a simple and fast abrasion test applicable for field use. The results of this program give a better basis for evaluating ilmenite for use as weight material in drilling fluids. Field Experience Two wells with ilmenite as weight material were drilled in the Norwegian sector of the North Sea in 1979. Both wells were drilled with the same drilling rig, and the total depths and maximum mud weights for Wells A and B were 12,192 ft [3716 m] and 11.7 lbm/gal [1.40 g/cm3], and 9,121 ft [2780 m] and 15.3 lbm/gal [1.83 g/cm3], respectively. Seawater-gel/lignosulfonate mud systems were used in both cases. Typical mud properties at maximum mud weights are given in Table 1. The drilling contractor reported improved rheological properties when ilmenite was used as weight material. Less fine particles, very low attrition rate, and no appreciable settling resulted in a stable rheology with limited need for water dilution and chemical conditioning. Excessive wear was observed in the mud mixing and storage system, whereas no excessive wear or corrosion was found on corrosion rings run in the low-velocity parts of the drillstring. The contractor reported increased change out of pump parts and noticeable wear in the centrifugal pumps. A washout, which could be caused by the use of ilmenite, appeared in a failsafe valve. Fig. 1 is a sketch of the circulating system, with calculated circulation velocities indicated. Visual inspections were carried out throughout the drilling period, and the parts corresponding to 6, 8 and 9 in Fig. 1 were reported to show excessive wear. As can be seen from Fig. 1, this corresponds to high-velocity parts of the circulation system. According to the drilling contractor's report, ilmenite was also difficult to water-wet and disperse, and air entrainment and foaming occurred. In addition, the reports claimed problems with excessive dust in the mud room. The dust adhered to pipes and walls, causing cleaning problems. JPT P. 969^

Introduction The need for solids control for drilling mud systems has been widely discussed in the literature and is gaining acceptance in drilling operations. Some of the major advantages of reduced drill-solids content in drilling muds are lower plastic viscosity, improved filter cakes, longer bit bearing and pump life, and improved penetration rate.Increases in the drill-solids content of muds generally lead to higher filtration rates and increased filter-cake thickness. Thick filter cakes aggravate the problem of differential-pressure sticking and cause increases in the torque and drag on the drillstring. Field observations indicate that filter-cake properties can be controlled by controlling the amount and types of solids in the mud.Surprisingly, drill solids cause a drastic reduction in bit-bearing life. King performed a series of experiments using an 8 3/4-in. bit with 50,000 lb weight and rotating at 60 rpm. When water was the circulating fluid, the bearings lasted 36 hours. The addition of formation cuttings decreased the bearing life to 26 hours. When the mud was treated with caustic and quebracho, the bearing life was reduced to 12 hours. When the same experiment was conducted using bentonite instead of formation clays, the bearing life increased from 36 to 38 hours. Additions of caustic and quebracho to this system did not reduce the bearing life, but when drill solids were added to this mud the bearing life decreased to 15 hours. New Mud-Treating System (Mud Cleaner) To overcome many of the limitations of current solids-removal techniques, a new mud-treating system was developed for weighted muds. This new system, called the Mud Cleaner, removes most of the drilled solids while retaining most of the barite and liquid phase of the mud. Unlike most barite-reclaiming or solids-removal techniques normally employed only after the drilled solids have reached an undesirable level, the Mud Cleaner is most effective when used as soon as barite is added to the mud system, and continuously thereafter. Continuous operation removes solids before they disintegrate to silt or clay size, thus preventing drill solids from accumulating in the mud system.Briefly, the new mud-cleaning system involves processing the mud through three separate stages:mud processing the mud through three separate stages:mud at well-circulation rate flows through a first screen (shale shaker), which removes large-size solids;the mud passes through a centrifuging stage (desilters), which passes through a centrifuging stage (desilters), which separates the mud into a low-density effluent and a high-density underflow - the effluent, comprising most of the liquid phase, returns to the mud system; andthe underflow, containing barite and drilled solids, flows through a second, smaller screen that is sized to pass the barite but to reject most of the drilled solids. The first screen can be provided by a conventional shale shaker that usually has a screen size between about 10 and 80 mesh. For most wells, shaker screens finer than 80 mesh are not capable of handling mud at normal well circulation rates. This means that mud passing the shale shaker contains large amounts of drilled solids. These solids upset mud properties and are the most difficult to remove. By pumping the mud tough desilters and screening the underflow, a large part of these fines can be removed without appreciable loss of barite.A sufficient number of desilters are used to process the entire mud stream. The desilters separate relatively light and fine particles from the heavier and coarser particles. Barite, which is present in the underflow along with drilled solids, is passed to the second screening stage. Most of the bentonite and liquid phase are discharged from the desilter in the effluent stream.For the second screen to reject additional drilled solids, its screen size must be much finer than the shaker screen, but must be sufficiently large to pass most of - the barite. The second screen is usually about 150 to 200 mesh. The flow rate of the underflow through the second screen is normally only about 10 to 20 percent of the well circulation rate. At such low throughput rates, the problem of screen blinding is not serious.For best performance, the fine screen requires special features. A vibrating screen that has performed quite well under field conditions is shown mounted on a portable skid below a bank of 4-in. desilters in Fig. 1. This device has a factory-tensioned screen that insures that screen life is not shortened by improper tensioning on the rig. A self-cleaning kit keeps drilled solids from plugging the screen and preventing passage of barite. This kit is a tray of short, plastic cylinders that are bounced against the screen by a 1,800-rpm motor; the rapid agitation keeps the screens clean and operative.The vibrating screens are adjusted at the factory to screen efficiently typical cyclone underflow material. The number and relative position of the upper and lower motor weights control the motion of the material on the screen surface. The horizontal throw of the material on each bounce is controlled by the number of top motor weights. The vertical amplitude is controlled by the number of bottom weight plates secured to the motor. The angle between the top and the bottom weights controls the spiral pattern on the screen. pattern on the screen. When the solids drop onto the screens, the vibration causes them to spiral away from the center. A "rope" of material forms and rotates around the outer perimeter of the screen. As the material passes the discharge spout, some of the rope is removed from the screen. JPT P. 1141

Laboratory and field studies have demonstrated that potassium cations at sufficient concentrations in water-based drilling fluids can effectively reduce the swelling and dispersive tendencies of clay-containing shales. Here is a unified classification method for relating the amount of water-sensitive clay in a shale to the occurrence and severity of wellbore problems. Introduction Proper selection of the drilling fluids to be used on Proper selection of the drilling fluids to be used on a particular wellsite is an essential phase of any carefully planned drilling operation. When this drilling is expected to encounter water-sensitive shale zones, the selection of the fluid becomes even more important. To maintain a stable borehole through such zones, an inhibitive drilling, mud will often be required. The design of successful fluids for this type of application depends largely on a knowledge of the physical and mineralogical characteristics of the shale and its behavior when contacted by drilling mud. We shall discuss here procedures and experimental results of laboratory tests in which a wide variety of fluids and shale types were used. The data should aid in designing effective inhibitive muds.Sensitive shale formations are encountered in most major oil fields throughout the world. These formations, referred to by a variety of names, including mud-making shale, caving shale, heaving shale, and sloughing shale, frequently cause wellbore instabilities. Drilling and completion problems associated with such instabilities include the accumulation of fill on the bottom after trips, tight holes, stuck drill pipes, solids buildup in the mud, hole enlargement pipes, solids buildup in the mud, hole enlargement and washouts, and poor primary cement jobs. Stable, gauge boreholes, reduced rig time, and lower total costs could be realized if efficient inhibitive systems were employed. Presently the only way to insure success in many problem formations is to use balanced-activity oil muds. Cost factors and handling considerations, however, suggest that water-based fluids be designed to perform the same function.In recent years many new water-based mud systems have been devised. Most of these rely on polymer or combinations of polymer and salt to polymer or combinations of polymer and salt to achieve a given level of inhibition. Low-solids drilling, using total or selective polymeric flocculants to achieve controlled clay yields, has been an important step forward. The new directions that drilling fluids in general and inhibitive fluids in particular are taking promise still further advances. promise still further advances. Causes of Shale Problems To investigate properly the nature of problems in drilling shales one must first study the various related physics-chemical processes. The general class of physics-chemical processes. The general class of shale problems presented in the introduction results from the following interrelated factors:shale hydration and swelling,dispersion of shale cuttings, andabnormal pressure.In addition, other processes and borehole conditions tend to aggravate the instability. These includetime spent in the open shale zone,in-situ stresses and formation characteristics, andmechanical and erosive action. Shale Hydration and Swelling Shales are basically sedimentary rocks that have been laid down over geologic time in marine basins. JPT P. 1089

Abstract Eight laboratory-prepared aqueous base drilling muds representing common mudtypes, and 15 aqueous base drilling muds sampled in the field, have been usedin an experimental investigation of the relationship between the streamingpotential developed across a mud filter cake and the differential pressurecausing filtrate flow. It has been established that the relationship is of the form, Es = kPy, where Es is the streaming potential, P the differential pressure and k and yare constants for any particular mud system at constant temperature. Beyond acertain minimum thickness this relationship is independent of filter cakethickness. Experiment has shown that both k and y are temperature dependentparameters and that in certain mud systems there is a critical value of P abovewhich the simple relationship Es = kPy ceases to hold. The constant k tends tobe a function of the mud resistivity at 77'F, but the exponent y has not beenfound to be related to any commonly measured mud property. Certain field experiments are described which serve to demonstrate that thetotal SP (self potential) developed opposite a formation may be quantitativelyaccounted for as the algebraic sum of an electrochemical potential and anelectrokinetic potential. A chart to permit the simple use of mean solutionactivities in the interpretation of electrochemical SP data is given and itsuse described. Various field methods for computing the electrokinetic SP component of thetotal SP are considered and rejected as being unduly complicated andinaccurate. It is shown that the employment of low resistivity drilling muds isessential if optimum accuracy is desired in the use of the S.P. curve for thepurpose of computing connate water salinities by the electrochemical SP method.The use of such low resistivity drilling muds is accordingly recommended. T.P. 2940

Abstract The conditions under which barium carbonate can be used to remove sulfatesfrom drilling muds are limited. The amount of sulfate remaining in solution inthe system after treatment with barium carbonate is shown to be a function ofthe concentration of the carbonate and barium ions and the concentration ofother electrolytes. Barium hydroxide may advantageously replace bariumcarbonate when the contamination is not entirely due to anhydrite (calcium inthe system is then stoichiometrically less than sulfate) or when the carbonateconcentration is high. The effect of substances such as quebracho, phosphates, and chromates, which form complexes or precipitates with barium, isdiscussed. Introduction As the complexity of the operations in drilling for oil has increased, moreattention has of necessity been directed to the problems pertaining to themaintenance of good drilling mud properties. As a result, chemical treatment ofmuds has become an important factor in recent years. Some of these treatmentshave been designed to eliminate the deleterious effects of contaminants inaqueous mud systems by precipitation or other means. The most common ofsubstances encountered during drilling include sodium chloride, cement, andcalcium sulfate while various other contaminants, usually in small amounts, maybe introduced from the water, clays, and other materials used in preparation ofthe mud. In certain cases, for example where continued salt-water flow isencountered or massive anhydrite is drilled, special muds may be used so thatthe physical properties of the mud will remain satisfactory for drilling. Inother cases, it is desirable to remove the contaminants so that solubleelectrolytes in the system are maintained at low values. For sulfate contamination, the common practice in the field is to add bariumcarbonate to precipitate the sulfate as barium sulfate. Ordinarily such aprocedure gives satisfactory results. There have been important instances, however, where addition of barium carbonate was not effective in removal ofsoluble sulfates from drilling muds, and it is to these cases that the presentpaper is directed. T.P. 2639

Abstract Since March 1945, the Magnolia Petroleum Co. has drilled 39 wells in Southwest Coastal Louisiana. All wells were drilled within a comparatively small radius, but the area provides a large variety of problems. The deepest well drilled was 13,518 ft, and the total depth averaged 10,977 ft. Throughout this period drilling mud control and types of mud handled were:phosphate,red lime (late conversion),red lime starch (early conversion),red lime starch oil emulsion,precision controlled low alkalinity-low lime content, andgel muds for completion purposes. Improvement has been obtained in effecting some or all of the following:more rapid penetration,reduction in drilling hazards,better evaluation of cores and logs, andbetter completions. The geological sequence of zones penetrated range from recent sediments at the grass roots through the Frio section. Anticipation of high-pressure zones and incompetent formations entails precision control of drilling mud weights, and the unconsolidated nature of the various zones requires constant attention to the filtrate, viscosity, and gel strength values. In the Chalkley field, particularly, this combination of problems exists, where the formation pressures and overburden weight density values are in very close proximity. Design of casing and drilling mud programs must be modified to fit each well. Introduction Field and research work on drilling fluids has made constant progress, enabling operators to prospect progressively deeper horizons. Numerous papers have been written on the theoretical aspects of drilling fluid development, but in the field engineers have found it difficult to evaluate the role of specific mud constitutents when dealing in terms of thousand barrel mud systems. For that reason field data is somewhat lagging in technical report writing. However, applications of new techniques in the field have usually paralleled, and in numerous instances preceded, research work.

Introduction Recent reports from the Soviet Union indicate that a fair degree of success is being attained with simultaneous drilling in certain fields. Although there is not a great deal of information available about the process, it is possible to determine the basic principles and some of the mechanical details involved. While any radical change in drilling methods is viewed with skepticism, only a critical evaluation can determine if it is justified or if some part of it may be made to serve our purposes. Simultaneous drilling is a method of drilling two directional wells alternately from a single rig and using a single drilling crew. While originally used with turbodrills, it lends itself to adaption so that it may be used with rotary drilling equipment. It is not intended for wildcat drilling, but will find its widest application in development drilling, particularly from offshore platforms. In simultaneous drilling, the two wells are drilled from the same rig, alternating the drilling from one well to the other each time a "round trip" is made. Actually, no round trips are made with this method of drilling the drill stem coming out of one hole being run down the other hole without the necessity of stacking the pipe. Rig Design In order to accomplish this with maximum speed and still retain simplicity in the drilling rig, the following rig is proposed. The floor of the simultaneous drilling rig is somewhat larger than that of the conventional rotary rig in order to accommodate a second rotary table and provide working space around each rotary (see Figs. 1 and 2). A single crown and traveling block assembly is used, which is shifted on a geared track by a series reversible motor between predetermined positions over each rotary as required. Two different mud systems are used with a single set of mud pumps and a manifolding system to give individual control of mud conditions in each well. Fingerboards and other auxiliary equipment are provided so that either rotary may be used for conventional drilling should the need arise. Two sets of terminal equipment are required, and certain other adaptations must be made.

Abstract Formation damage, i.e., reduction in permeability, has been generally attributed to clay minerals which expand or disperse upon contact with water that is less saline than the connate water. Laboratory studies show that permeability reduction can also occur in formations containing only nonexpandable clays, such as illite or kaolinite, and can be caused also by changes in pH. Furthermore, pH changes can damage even formations that are essentially free of clay. It is suggested that permeability reduction is due to the small passages being blocked by particles, which may be dispersed clays, cementation material or other fine particles. These particles are dislodged by dispersion of clays due to changes in salinity or by dissolution of calcareous cement by acids, or of silicaceous cement by alkaline solutions. In working with reservoir cores, it was found that extracted cores damaged more easily and extensively than nonextracted cores. The extent of damage depended also on temperature. Introduction Permeability is an important property of porous media and has been the subject of many studies by engineers and geologists. Many of these studies are concerned with formation damage, i.e., reduction in permeability, resulting from exposure of oil-producing formations to water substantially less saline than the connate water. This effect causes understandable concern since during drilling, completion and production phases formations are often exposed to fresh water. The damage resulting from contact with relatively fresh water bas been attributed to expansion and dispersion of clay minerals. During laboratory investigation of the use of NaOH as a wettability reversal agent to increase oil recovery from oil-wet reservoirs, several cores used in the displacement studies suffered loss in permeability. Despite the traditional usage of NaOH for conditioning aqueous mud systems, the role of the caustic filtrate in wellbore damage seems to have been overlooked. Browning has recently reported on the effects of NaOH in dispersing clay minerals but he was concerned only with complications that may arise in drilling massive shale beds. The following study was made to examine the role of pH and salinity changes in core damage. Where corns from reservoirs were used, tests were performed with extracted and nonextracted cores both at room and reservoir temperatures, since it was felt that the test environment and core condition may affect the results. Because of its limited coverage and exploratory nature, this study is not intended to provide answers to field formation damage problems. It is hoped that it will encourage research into new aspects of the permeability reduction problems, particularly those allied to new recovery and production processes. PROCEDURE In all permeability tests, fluids were pumped through the cores at a constant volumetric rate. Only deaerated fluids and reagent grade chemicals were used. The fluids were passed through two ultrafine filters before injection to remove any entrained particles. The cores, with the exception of the unconsolidated cores, were mounted in Hassler holders. Water was used to transmit pressure to the sleeve. The inlet endpiece had two entry ports which permitted scavenging one fluid with another to avoid any mixing in the small holdup volume. The cores were flushed with CO2 gas, evacuated for 5 to 6 hours and saturated with the first liquid at a pressure of 1,000 psi for 24 hours to eliminate any free gas from the cores. Pressure differences up to 20 psi were measured by transducers, calibrated in inches of water and continuously recorded. For greater pressure drops, gauges were used. All reservoir cores were cleaned with a light refined mineral oil, then with heptane, and finally dried with CO2. Compatibility tests showed that no precipitates formed when mineral oil and the crudes were mixed. Some cores were extracted in Dean-Stark-type solvent extractors using xylene and trichloroethane and dried in a vacuum oven at 450F.Each test consisted of a sequence of water, test solution, and again water flow. RESULTS AND DISCUSSION STUDIES IN BEREA CORES Salinity Contrast Berea cores 2-in. in diameter and 12-in. long were cut from sandstone quarried in Cleveland, Ohio. The clay minerals were identified by X-ray diffraction to be chlorite, kaolinite, illite and interlayered illite. Flow of fresh water or 30,000 ppm brine does not cause any permeability reduction (Fig. 1). However, after injection of brine the core is readily damaged by fresh water. Damage starts almost instantly as the fresh water injection is begun, and at a cumulative injection of 1.2 PV fresh water, the permeability has dropped from 190 to 0.9 md. Upon continued injection, the effluent contains clay minerals dislodged from the core. JPT P. 1449ˆ