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Moving into the next decade, wells in the Middle East are becoming more challenging as the deeper and more complex plays are exploited. This environment will be challenging from a torsional and tensile loading standpoint, and will be dynamically very active. This type of environment combined with high levels of H2S calls for a new high grade of sour service pipe. The Middle East is also opening up to the idea of high speed telemetry and wired pipe economics that call for a long lasting pipe product. When using sour service pipe that is traditionally limited to 105 KSI grades, even with an optimized string design, drillers sometimes have no other option than to sacrifice the margin of overpull, risking losing the well if fishing is unsuccessful. Alternatively, they can elect to use drill pipe, which is not suited for use in this corrosive environment, generally using API S135, with a risk of parting the string due to H2S embrittlement. To address these operational limitations, the pipe body, which is the drill pipe limiting member in tension, has to come with higher material strength and at the same time exhibit improved Sulfide Stress Cracking (SSC) resistance compared to API S135 grade. A novel grade of drill pipe was developed over a period of two years that is the strongest sour service drill pipe the industry has to offer to date and gives drillers an extra 19% of tensile capacity with its 125 KSI material yield strength. This new grade has been ordered for use in various regions of the world and for numerous applications. At this time, it is being used for intervention and stimulation operations in the Gulf of Mexico (GOM), and drilling long, extended reach (ER) wells with wired telemetry drill pipe in the Middle East. This paper presents the phases of the grade development and discusses testing requirements for the crossover between strength and SSC resistance. It also includes statistical data on the first full scale manufacturing tests. Finally, it outlines the products expectations for field applications.

Over the last 30 years, Coiled Tubing (CT) has become one of the most important tool for wellbore interventions, completions and even drilling. The success of this technology lies in its high degree of flexibility which is based on the conscious destruction of its own working material – the Coiled Tubing itself – caused by low cycle fatigue. The current standards and best practices for the fatigue simulation are based on testing frames that are as old as the coiled tubing itself. In a working environment such as the oil and gas industry, where safety of operation is a key parameter, a reliable fatigue model that allows to track the fatigue damage and to stop using a pipe before it breaks becomes critical. Therefore, this paper provides a discussion of the existing fatigue testing setups and an inside of the prediction models. The second part of the paper will focus on discussing the true loads of a coiled tubing used for drilling applications. Finally a newly built for purpose testing facility is presented, showing the latest developments in accurate testing of coiled tubing used for deep drilling applications. The experimental tests have shown a good compatibility with existing testing setups, but the new added capabilities exceed the actual performance, and allow the development of a new coiled tubing fatigue prediction model.

Harnessing geothermal energy faces many of the challenges encountered in the exploration and production of oil and gas. Deep drilling is a necessity to attain sufficiently high temperatures for successful recovery of unconventional geothermal energy, such as in Enhanced (or Engineered) Geothermal Systems (EGS). The challenge of deep geothermal exploitation is comparable to that posed by high-pressure, high- temperature oil and gas projects. Accessing such deep targets, and the need for suitable well completions, means operators incur increased capital and operational costs. To date, the implementation of EGS, following the original Hot Dry Rocks (HDR) model, has been dogged by technical problems, lower-than-expected performance and poor public image, as they typically require the "engineering" of the reservoir by artificial stimulation in order to create the necessary heat exchange in the subsurface. Here, conventional and unconventional deep geothermal development well concepts are reviewed, breaking down the technologies into three categories: doublets, single well (open loop) solutions and single well (closed loop) heat exchangers. This paper then focuses on the original Borehole Heat Exchanger (BHE) concept for shallow applications, and - based on recent experience with medium-depth BHEs for direct use/district heating - discusses variations proposed in the public domain for deep geothermal systems, with the ultimate goal of generating electricity under current economic conditions.

Directionally drilling of 16-in hole section in a deep gas field had been always a challenging task to the Operator. This is mainly due to the lithology, consisting of very hard limestone with thin bed of shale where the kickoff would generally start around 11,200 ft. The operator attempted to kick off the 16-in hole using both roller cone TCI bit and PDC bit technology and utilizing a mud motor as the drive mechanism. This method provided an unacceptable low rate of penetration. In addition, there were difficulties in achieving the directional control, and multiple bit trips were required to finish the required directional work. The operator determined that a new bottomhole assembly (BHA) would be needed to efficiently drill this section to the desired inclination and azimuth in one run, while meeting the performance requirement. Multi-function teams were organized to aggressively look for new BHA configuration that could consistently drill this interval in one run with a good rate of penetration. Historically the sliding ROP in the curve section consumes the maximum time (as low as 2-3 ft/hr) with PDC bits and Motor Kick off due to tool face control. To mitigate this, Motorized Rotary Steerable System was selected for this section. The section was kicked off very successfully achieving the required build rates with double the ROP compared to previous wells. The team collaborated to custom design a new bit and BHA with new drive system that would achieve the operator's objectives. The collaborative effort resulted in achieving new records in drilling, with the fastest ROP, 50 - 100% higher than previous attempts on the fastest offset wells ever drilled in a 16-in hole and precisely drilling to the planned trajectory. The application of this new technology proved to customer that what was not previously possible could be done now more efficiently and cost effectively.

The rock in deep strata of Wuxia area in Junggar Basin is abrasive and with low drillability. Part of the formation sections with abundant fractures, which leads to mud lose frequently. The exploration progress has been slowed down by low drilling speed and accidents. The exploration department of Xinjiang Oilfield Company preferred underbalanced drilling technology on well F8 and A1 on the basis of feasibility analysis of UBD technology in Permian strata. The applications reduced lose circulation effectively and promote the rate of penetration considerably. Well F8 and A1 used foam and nitrogen as underbalanced drilling circulation medium respectively. The wellbore sizes are 215.9 mm. The rate of penetration in underbalanced drilling sections are quintuple than conventional rotary drilling. It saved more than 20 days in the overall drilling time. The conversions between foam/nitrogen with mud were successfully once only. There was no losing circulation during underbalanced drilling progress. The successful application of underbalanced drilling technology in deep strata of Wuxia area solved the deep drilling speed improved problems entirely. It reduced mud lose and promote drilling speed. The drilling overall time and exploration cost has also been decreased greatly. The innovation application provides a new method for deep drilling speed improved in this area. In the passed drilling, the ROP of advanced cone and PDC bits was nearly 0.65 m/h, and the ROP was no more than 0.92 m/h even with turbodrills and impregnated bits. However, the ROP of underbalanced drilling section has promoted several times than conventional drilling. ROP optimizing was substantial versus direct offset wells that experienced quintuple drilling time through the same formation. With this success, the team has accumulated valuable experience of deep drilling for Junggar Basin.

Hydraulic pulsed cavitating jet drilling is a new combined drilling technology. In this technology the hydraulic pulsed cavitating jet generator is installed upon the bit in the drilling process. Based on modulating pulsed jet and cavitating jet, a new drilling tool is designed which couples advantages of both pulsed jet and cavitating jet. When drilling fluid flows through the tool, fluid is modulated to pulse and cavitation. Thus, pulsed cavitating jet is formed at the outlet of the bit nozzle. Because of jet pulsation, cavitating erosion and local negative pressure effect, bottom cuttings cleaning efficiency is enhanced and the rate of penetration (ROP) is improved. This paper studied the mechanisms of improving the ROP and cuttings cleaning efficiency in hydraulic pulsed cavitating jet drilling. Hydraulic pulsed cavitating jet drilling technology has been applied in 8 oil fields in China, such as Tarim oil field, Xinjiang oil field, etc. The tests in more than 40 wells showed good applicability of the tool to bit types, formations, drilling fluid densities, etc. Hydraulic pulsed cavitating jet can mate with helicoid hydraulic motor and Power V system drilling technology, this technology also can be used in underbalance drilling. The test well depth is 1274 ~ 6162 m. As the result, ROP was improved by 10. 1 to 104. 4 percent and the maximum operation time is about 260 hours in wellbore. Pulsed and cavitating jet coupling can afford an effective approach to improve ROP in deep and ultra-deep well.

Full-scale laboratory testing was conducted under a joint industry and Department of Energy program titled "Optimization of Deep Drilling Performance; Development and Benchmark Testing of Advanced Diamond Product Drill Bits and HP/HT Fluids to Significantly Improve Rates of Penetration." In total, seven bits and twelve different drilling fluids were tested in three different rocks at a variety of drilling parameters. Phase 1 results have been reported in a previous paper (Judzis et al., 2007). This paper presents the results from Phase 2 of the study. The goal of Phase 2 testing was to evaluate bit features and mud additives that might enhance ROP under high-pressure conditions. The test protocols developed in Phase 1 to simulate Arbuckle play and Tuscaloosa trend drilling at pressures in excess of 10,000 psi were employed to evaluate these features. Significant findings of Phase 2 include the following: Mud additives can substantially enhance ROPs in high-pressure conditions and may play a larger role than bit design features.A 16-ppg cesium formate brine increased ROPs 100% as compared to 16-ppg oil-based mud in Carthage marble and Mancos shale. The cesium formate improved ROPs by increasing both the efficiency and the aggressiveness of the bit.A 16-ppg oil-based mud weighted with fine particle size (D50 ≈ 1-3 microns) manganese tetroxide increased ROPs in Crab Orchard sandstone 100% as compared to a similar mud weighted with conventional barite. The manganese tetroxide improved ROPs by increasing the efficiency of the bit, but did not have a measurable effect on bit aggressiveness.Phase 2 tests continue to support the conclusion of Phase 1 that specific energy consumed while drilling is substantially higher than the confined compressive strength (CCS) of the rock.

Summary Three drillstring fatigue failures occurred while drilling two deep wells below 16,500 ft true-vertical depth (TVD) in the US midcontinent region. All the failures occurred across 2°/100 ft- to 3°/100 ft-dogleg severity (DLS) intervals from 6,000 to 8,000 ft. The well conditions (i.e., pipe condition and directional plan) were not significantly different from other deep wells in the area, which had not failed. A deep-well drillstring failure study was conducted, which included a review of drillstring-inspection reports, daily drilling reports, digital data, technical literature, and engineering analysis for the two wells. A cumulative fatigue analysis (CFA) modeling technique taking into account specific well conditions [i.e., wellbore geometry, rotary speed, rate of penetration (ROP), hook load, and drillstring configuration] was applied. The model indicated that drillstring failures would occur across shallow doglegs mainly because of high hang-down loads combined with slow ROP. The results of the study led to the development of new deep-well design criteria and implementation of new drilling guidelines. The new guidelines included the use of look-ahead CFA modeling when approaching drillstring endurance limits to minimize drillpipe-fatigue failures. Look-ahead CFA modeling and the new drilling guidelines were used on two subsequent deep wells in the area, leading to successful drilling to total depth (TD) of 18,000 ft TVD without failure. One of the wells had a 1.4°/100-ft DLS (calculated based on 100-ft survey spacing) at 1,500 ft, and drillpipe shuffling was required to prevent drillstring failure in the deep-hole section. The drillstring-fatigue failure prevention guidelines apply to deep wells drilled worldwide. Introduction BP America, Inc. experienced three high-load cyclic fatigue tube failures while drilling in the US midcontinent region's deep Anadarko basin. All of the failures occurred within a four-month period on two wells drilled by different rigs. The three fatigue failures occurred in the highest shallow dogleg interval of the wells, and all three failures were in the inclination-angle dropping section of the well. In Well A, poor mud properties caused the hole to pack off, leading to a heat-related tensile failure of a crossover in the bottomhole assembly (BHA). An unsuccessful fishing job for the remaining BHA led to a sidetrack. The sidetrack around the fish created shallow doglegs and led to the two drillpipe-fatigue failures in Well A. Shallow directional walk problems combined with a small directional target created shallow doglegs in Well B. The well scope was also changed at TD to drill 375 ft deeper. Mud circulation was lost, and the drillstring was rotated without circulation while building mud volume. Well B subsequently experienced a fatigue failure while pulling out of the hole at TD of 16,628 ft. After these failures occurred, a comprehensive study was performed to understand why these two wells experienced drillpipe failures while other area wells with similar conditions did not experience a failure. The study included a review of drillpipe-inspection reports, daily drilling reports, digital drilling recorder data, and engineering analysis.

Drilling ultra-deep (UD) wells places significant requirements on the drill string. Lengthy drill strings lead to high tensile loads which can lead to slip crushing of the drill string, hoisting capacity issues and drill pipe collapse capacity concerns at the blowout preventer (BOP). BOP shear rams may also have difficulty shearing today's high strength, high toughness drill pipe. BHA connection failures pose greater risk and cost at UD well depths. This paper analyzes the many challenges associated with drill string designs specifically for UD drilling. It presents emerging drill string technologies that are solutions expected to increase depth capability for the industry's continued advancement of deep drilling operations.

A critical cost in future deep oil and gas recovery is the cost to drill a well. This cost is dominated by the rate of penetration (ROP) that becomes increasingly important with increasing depth. Improving the technology of drilling and increasing the ROP will lower the cost to drill a well. This improves the economics of deep exploration and development, potentially increasing drilling activity, increasing production and supply, lowering the cost to the consumer and improving the economy. Industry partners and the U.S. Department of Energy (DOE) successfully completed benchmark testing of advanced diamond bits and high pressure/high temperature (HP/HT) drilling fluids at high pressures. The paper describes the results of this testing and identifies factors limiting ROP performance at great depth, and the development of drilling fluid systems and bit design philosophy to significantly improve drilling performance. Benchmark results match very well with data from target field applications. This project is part of the DOE Deep Trek program. Sixteen full-scale tests of 6 inch bits were conducted at wellbore pressures greater than 10,000 psi. Results from high-pressure tests with water and base oil showed very high ROPs are possible before mudding up. When drilling through hard sandstone penetration rates can drop 70 to 80% on switching to a weighted mud. These data emphasize the importance of mud technology in high-pressure applications. Performance of polycrystalline diamond compact (PDC) bits showed in many cases substantial improvements over roller cone insert bits. Cuttings from Carthage marble and Mancos shale appear to be compressed agglomerates of fine particles and Carthage marble cuttings had low compressive strengths. The study has concluded that opportunities for improvements in both bit design and smart HP/HT drilling fluids are possible. While rock properties change continuously with pressure the cutting mechanisms at great depths change much more dramatically. Changes in bit design and mud composition, using next generation technology, will be evaluated in Phase II testing. The significance of improved ROP for deep oil and gas plays include opportunities to reduce well costs and improve the economics of deep exploration and development plays. The net result for operators is cost reduction as well as an improved position on reserves.

KOC has been drilling deep HPHT wells from the mid 1980’s, and during this time the Kuwait deep well prospects have become deeper and more challenging. The rigs utilized to drill these wells have evolved over the years to meet these challenges, with new technologies being used to improve both operational and safety aspects. Five years ago an enhanced rig type upgrade was introduced with the application of Top Drive, additional third 1700 HP mud pump and larger 5 1/2" O.D. drill pipe. This resulted in a step-change improvement in drilling performance. In 2003 KOC began a project to look into the radical re-design of the deep rig specifications. Hamad Al Hamad and Partners was awarded the contract to complete the detailed design, procure and operate the rig, and National Oilwell Varco was assigned as the main rig construction contractor. For the rig design certain new concepts were to be developed in readiness for a future campaign of deep HPHT exploration wells. These included the following; the rig should be safer and more automated, the capacity of the main equipment items and the mud system should be state of the art both in capacity and equipment specifications, the 15M BOP stacks should be re-designed to minimize handling, and the rig should be adapted for operation in the harsh summer conditions in Kuwait. This paper will discuss the evolution of Deep Drilling Rig design in Kuwait, the design and specification of the new HAH-124 rig plus the construction/rig-up of the unit. The case study will also focus on lessons learned during this process and conclude with recommendations for future new rig builds.

The U.S. Department of Energy (DOE) has undertaken a baseline study designed to provide current drilling technology and cost bench-marks as reference points in evaluating future cost improvements to be derived from technology advancements. Deep formations are one of the sources of natural gas that will play an important role in meeting the growing need for natural gas in the U.S. The Energy Information Agency estimated that 7 % of U.S. gas production came from deep formations in 1999. This contribution is expected to increase to 14 % by 2010. A deep-well database has been completed that categorizes wells by total depth, targeted formation, geographic location, completion technique, and operator. In addition, information was gathered from operators and service companies reporting the current status and future directions of drilling technologies, which was then compiled into a condensed format. Bit and downhole motor and turbine technology have improved significantly over the past several years, leading to faster rates-of-penetration (ROP) for deep wells. Polycrystalline diamond compact (PDC) bit technology is one of the most significant technology improvements in the drilling industry over the last 20 years. Current and proposed well-construction methodologies that should continue to reduce costs of drilling deep and extended-reach wells include solid expandable tubulars and the concept of casing drilling or liner drilling. However, these concepts are still evolving. As these and other new technologies are applied, the results of this benchmarking effort provide the basis upon which future relative progress and cost savings can be identified and measured.

With the resurgence of deep gas drilling in the Gulf of Mexico specifically on the shelf, the focus has shifted to the need for a new design in offshore drilling units. This paper will discuss the reasons for pursuing exploration in such an environment, why it is more cost effective to build new rigs instead of modifying existing units, and the design and equipment used to enhance its performance.

Many companies show a strong commitment to the environment and to the prevention of pollution in their policy statements. But reality shows that the introduction of most environmental programs fail because of limited knowledge about the actual situation within a company. ISO14001 requires a company to establish procedures to identify and control the environmental aspects of its activities. The identification of significant impacts enables the company to define environmental objectives and targets. The real knowledge of mass balances and material flows offers an unique possibility for cost savings by switch to less waste producing or energy demanding technologies.

As the search for recoverable oil reserves moves to smaller, deeper, and hotter wells, measurements while drilling (MWD) requirements have grown increasingly challenging. MWD tools must survive temperatures of up to 350°F (175°C), pressures of up to 22,000 psi, and a wide variety of mud conditions. Moreover, deeper wells cause higher attenuation of the MWD signals and therefore require more signal power downhole. This paper presents the development of a new-generation retrievable MWD tool that has been proven to deliver the reliability required by the industry, even in deep, high pressure, hot wells. Four case studies illustrate the tool's reliability and performance under extreme conditions: In the Villafortuna field in Italy, this new generation MWD tool drilled the deepest horizontal well in the world, at depths greater than 20,000 ft with a maximum circulation temperature of 356°F (180°C) and downhole pressures exceeding 20,000 psi. In the Gulf of Mexico, the tool enabled BP to complete a deepwater well at a depth of 26,442 ft with a flow rate as low as 62 gpm, extending the far reaching capabilities of slimhole MWD equipment. In the Austin chalk in Texas, the tool operated reliably in drilling muds containing 30% solids. The tool operating life was increased by a factor of three through design improvements. The final case study documents the benefits of a tool designed for extreme environments, when used in difficult but not extreme conditions. An exemplary run of 315 hours at 287°F (142°C) is discussed. This new generation of slimhole MWD technology finally meets the challenges presented by the deeper and hotter wells at the leading edge of petroleum exploration.

In recent years, many wells have been constructed that are subject to extreme conditions. Two extreme conditions that can pose a particular challenge during the completion of a well are low temperature, for example in deepwater applications, and high-pressure and high-temperature, encountered in HPHT wells. The products and processes that are normally used to cement wells may be insufficient to create zonal isolation for these extreme conditions. This paper presents methods to help design and execute effective cement jobs for HPHT and deepwater, low temperature wells. First of all, recommendations are outlined for the deepwater conditions. Drilling fluid removal, sealant placement, and sealant sheath strength development are all affected by extreme conditions and are therefore designed accordingly. In order to help determine how strong the sealant sheath needs to be, formation properties are taken into account as well as the operations to be performed during the life of the well. These operations include well testing, stimulation, production, and injection. The paper goes on to discuss the advantages of new products and processes for cement wells under extreme conditions. The laboratory testing procedures, pre-job design procedures, job implementation and evaluation procedures that were used to test the new products and processes are described. Finally, guidelines are given for optimized designs for HPHT and low temperature wells using these products and processes.

ABSTRACT Deep drilling of Permo-Triassic / Palaeozoic section in Abu Dhabi area is, generally, costly and risky: Many unforeseen problems were encountered while drilling resulted in that some wells have not achieved their objectives in evaluating the deep reservoirs. One of these problems was the high pressure formation salt water flow from Gulailab (Jilh), Lower Khuff and the Pre-Khuff formations. Ths phenomena is most likely due to the presence of anhydrite /shale seals trapping the high pressure salt water flow migrating from the underlying reservoirs. If the mud logging unit, the drilling crew and the geologist on the well site succeeded to observe the pressure seal and/or other warning signs of kicks, they will predict early a high pressure zone before facing the problem. Thus, the drilling crew can be alert to monitor the hole and take necessary precautionary measures to continue drilling the hole safely. The paper will discuss case history examples on the high pressure formation salt water flow (HPFSWF) in deep drilling, from offshore/onshore areas in AbuDhabi. I. INTRODUCTION Pronounced overpressured zones were encountered in many fields in Abu Dhabi, mainly while drilling the deep Permo-Triassic/Palaeozoic wells. The overpressure phenomenon is a complicated issue and is associated with many geological factors e.g. effect of depth on overpressure distribution, facies changes as well as reservoirs and seal properties. The type of problems encountered due to overpressuring in the Gulailah/Jilh, the Khuff and the Pre-Khuff sections vary from one well to another, regardless of the location. Heavy drilling fluids were generally used and intermediate casings were usually set in these formations to overcome these problems. The main obective of this paper is of two folds: to highlight drilling problems with case history examples from offshore and onshore wells (Fig. 1)and to attempt to find geolgical explanations for the following questions:Is the overpressure zones in the Abu Dhabi basin a regional or local phenomenon?What is the lateral and vertical extent of the overpressure systems within the basin?Does underpressure also occur within Abu Dhabi basin?How does overpressure relate to sedimentation, lithology and geothermal gradient?What are the causes of overpressure in Abu Dhabi basin? Obviously, these questions are essential for hydrocarbon exploration and development in the Abu Dhabi basin. II. DRILLING PART A. PROBLEMS ENCOUNTERED WHILE DRILLING DEEP WELLS IN ABU DHABI AREA About 27 deep wells have been drilled in Abu Dhabi Area below Triassic, until the end of 1995. Most of these wells faced one or more of the following problems: Drill string problems, fishing operations, formation problems, casing cementing failures, mud problems, casing problems … etc. One of the formation problems which is classified as the most potential, expensive and operationally difficult to handle is the HPFSWF encountered while drilling the following hole sections: Jilh/Gulailah, Khuff and Pre-Khuff. These problems occurred in six offshore wells and four onshore wells. Each well has one or more of HPFSWF problems. Some of these problems resulted in that the well primary and/or secondary objectives have not heen achieved in spite of the high cost and time spent on the problem. To illustrate the above problems, four problematic wells will be presented in this part named F-1, Y-1, U-1 and S-1. The problems will be discussed under three cases as follows: Case (1) Gulailah/Jilh formation, case (2) Lower Khuff (LK) section and case (3) Pre-Khuff (PK) section. A. PROBLEMS ENCOUNTERED WHILE DRILLING DEEP WELLS IN ABU DHABI AREA About 27 deep wells have been drilled in Abu Dhabi Area below Triassic, until the end of 1995. Most of these wells faced one or more of the following problems: Drill string problems, fishing operations, formation problems, casing cementing failures, mud problems, casing problems … etc. One of the formation problems which is classified as the most potential, expensive and operationally difficult to handle is the HPFSWF encountered while drilling the following hole sections: Jilh/Gulailah, Khuff and Pre-Khuff. These problems occurred in six offshore wells and four onshore wells. Each well has one or more of HPFSWF problems. Some of these problems resulted in that the well primary and/or secondary objectives have not heen achieved in spite of the high cost and time spent on the problem. To illustrate the above problems, four problematic wells will be presented in this part named F-1, Y-1, U-1 and S-1. The problems will be discussed under three cases as follows: Case (1) Gulailah/Jilh formation, case (2) Lower Khuff (LK) section and case (3) Pre-Khuff (PK) section.

Attention to detail and the utilization of operational techniques that have been around since the 1960's and 1970's have resulted in the drilling of directional platform wells over 18,000 feet deep, with 40-45 degrees of angle, in just 23 days from spud. Although this paper discusses deep, platform drilling, the techniques are basic and they have a broader utility to a range of drilling applications in other areas, on land and offshore. This paper demonstrates the importance of staying operationally and mechanically simple when executing sophisticated, deep, directional well plans.

Abstract The world's deepest short radius horizontal well was drilled by Crescent Petroleum in their offshore Mubarek Field in the second quarter of 1992. The reservoir objective was the Thamama formation which is a deep, hot, fractured Limestone containing a sour gas condensate. The well was built to horizontal at 14,115 ft TVD and over 1000 ft of the Thamama reservoir was drilled in 5-7/811 hole using short radius drilling equipment and a mixed metal hydroxide drilling fluid. The welt was drilled without any major problems and a 3-1/2" perforated Liner run to TD successfully. This paper discusses the operational planning for the well including the reasons for the choice of short radius technology, the planning considerations for its application in this harsh environment and the selection of the mud system for use with the short radius motors at the high bottom hole temperature encountered in the Thamama reservoir. A history of the overall drilling operation is discussed. The success of the short radius equipment and the mixed metal hydroxide mud system is evaluated and their performance, interaction and Limitations are addressed. The problems encountered while drilling are considered and possible solutions or procedural changes which will improve performance in future wells are presented. Introduction The Mubarek Field ties in the Arabian Gulf at the head of the Strait of Hormuz. It is located 30 miles offshore Sharjah in the United Arab Emirates. The field trap is a conventional turtle-back structure induced by movement of the underlying Hormuz Salt. The structure is approximately 15 km × 10 km with gentle structural dips. The Field consists of two hydrocarbon bearing units (see figure 1). The oil bearing, but now depleted, Ilam/Mishrif unit and the recently developed sour gas condensate bearing Thamama Unit. Both units are carbonates of Upper Cretaceous Age with the Thamama, the focus of the study, lying approximately 1200 ft TVD below the Ilam/Mishrif. The Thamama reservoir consists of a series of alternating porous and non-porous Limestone layers which vary in thickness from 30 ft to 100 ft. The average porosity of the porous Layers is 6.5%, the original porosity having been severely reduced by diagenetic alteration and secondary cementation. The average porosity of the non-porous Layers is less than 2%. Observations from other wells drilled in the reservoir indicated that:although the bulk of the hydrocarbons are contained within the porous Layers production is only encountered wherefractures are present.due to the gentle structural dip the degree of fracturing is not severe and is heterogeneous.observed fractures appear to be focussed in the tight zones. The most commonly fractured is Zone 1A some 40 ft thick located 44 ft TVD below top Thamama and situated between porous Zones 1 above and 2 below. The objective of the horizontal section was to penetrate Zone 1A and Zone 2 to exploit the relationship between fractures and porosity thus enhancing productivity. Studies of the fracture orientations indicate a preferential fracture trend to the North East. The horizontal well bore was programmed to intersect the fractures perpendicular to the fracture plane and exploit them to full advantage. P. 669^

Abstract Poor planning, wishful thinking, and lax or inept supervision combine to cause most oil field problems. Neglect or misinterpretation of available data and improper engineering evaluation of consequences of designs and techniques lead to often disastrous results. Inadequately trained, over-worked and occasionally lax supervisors fail to apply or misapply available technology. Training at all levels suited to the level and applicable to current problems reiterated to the point performance becomes automatic is the first step in solving well problems. problems. TEXT During the last five years I have published several papers and magazine articles published several papers and magazine articles on the basic theme of poorly trained personnel and inadequate use of available personnel and inadequate use of available technology in the oil and gas drilling industry. After that period of time it appears that technology has advanced substantially and performance has advanced in some areas. The problem is wells are being drilled under more difficult conditions of environment, depth, pressure, corrosive well fluid and inflated cost. The net result is we are certainly not improving our relative position measurably. The industry seems to be content to operate at a fairly constant level of inefficiency. As a part of my consulting work I am called upon to critique a number of drilling operations. These are generally wells that have been extremely costly, failed to reach their objective, blew out, had some catastrophic failure, or some combination of any or all of those. Every one violated several well known widely accepted engineering principles. In no case is there any indication that these violations are careless, negligent or derelict. In many cases the desire to drill inexpensive wells tends to influence the designers estimate of the probability of encountering abnormal pressures and of getting those pressures on casing. In fact is appears that many pressures on casing. In fact is appears that many designers start by assuming the well will be dry and basing all their work on that premise. Although by no means restricted to the Oklahoma area this practice leads to a large number of the Morrow blowouts there. It is true that if every well were designed to accommodate Morrow pressure costs would be excessive and quite a pressure costs would be excessive and quite a few would be eliminated. There must be an answer that will allow drilling all reasonable prospects and yet minimize serious problems. A higher quality engineering evaluation of risks, probability and consequences of problems and quality probability and consequences of problems and quality supervision at critical times will do much to reach that goal. Greater problems in this regard occur in deep high pressure wells and it is not confined to any area. Two problems both engineering related but one controlled by unqualified management and the other by established practice and poor engineering evaluation occur in all provinces. In the past year wells have been drilled onshore and offshore in the Gulf Coast on which 5000 psi working pressure blowout preventers were used psi working pressure blowout preventers were used on protection strings where surface pressure could and did exceed 9000 psi. Fig. I.

Discussion of this paper is invited. Three copied of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The prospect of higher gas prices has triggered new interest in deep drilling below 10,000 feet in the huge Appalachian Basin. Scant past exploration of known deep structures is evidenced by the fact that only 42 wells have been drilled below 10,000 feet in the seven state area. Drilling costs have been high due to some problems peculiar to this area. A sectional hole analysis of these problems and recommended practices based on past experience shows ways to reduce these costs and encourage additional exploration. Introduction Prospective higher gas prices, nearness to market, and large unexplored structures are the incentives that have renewed deep drilling in the Appalachian basin. Several major operators are now drilling wells below 10,000' in the seven state area. This has encouraged the application of new drilling techniques in an attempt to reduce high costs of these deep wells. This paper will (1) review briefly the past and present deep drilling activity in this past and present deep drilling activity in this basin, (2) present a generalized drilling plan that can be of help to new operators entering this area, (3) discuss drilling problems and solutions, and (4) review some special contract and environmental problems peculiar to this area. The Appalachian Basin covers all or a portion of the seven states of New York, portion of the seven states of New York, Pennsylvania, Ohio, Maryland, Virginia, West Virginia, Pennsylvania, Ohio, Maryland, Virginia, West Virginia, and Kentucky (Figure 1). Covering an area of about 175,000 square miles, the basin contains many deep geologic structures which have been recognized for years and discussed in numerous articles. Scant attention had been paid to these deeper prospects, however, until recent encouragement of higher gas prices triggered the leasing of millions of acres by several major companies new in the area. It is ironic that the birthplace of the commercial oil industry should have been overlooked so long as to exploration below 10,000'. A survey shoves only forty-two wells have been drilled in the entire area to date (Figure 1). Several wells currently are being drilled to these deep structures, and new depth records have been set. These efforts are very expensive as to drilling costs, and encourage application of cost reducing procedures. Problems causing the high costs of drilling range from surface glacial drift and boulders to extremely hard quartzites, salt sections, and "trapped pressure shales." Dry hole costs in the basin can range from $27/foot for an 11,000' hole drilled to TD on air with no problems to as high as $150/foot for a typical 20,000 foot well which will encounter several problems, including at least one sidetrack operation. How Deep Can We Find Economic Oil and Gas Accumulations? 5177 Hunt, John M., Woods Hole Oceanographic Institution Copyright 1974 American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Deep Drilling and Production Symposium of the Society of Petroleum Engineers of AIME, to be held in Amarillo, Texas, Sept. 8–10, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the Journal of presented. Publication elsewhere after publication in the Journal of Petroleum Technology or the Society of Petroleum Engineers Journal is Petroleum Technology or the Society of Petroleum Engineers Journal is usually granted upon request to the editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copied of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The development of drilling equipment with increasingly greater depth capability should take into account the maximum depths at which economic hydrocarbon accumulations will be found. The origin, accumulation and destruction of hydrocarbons is controlled primarily by temperature and time. Most hydrocarbons form at subsurface temperatures ranging from 125 degrees F to 350 degrees F, equivalent to depths of 3,500 ft. to 20,000 ft. in a typical basin. High temperatures >350 degrees F), or long exposure to moderate temperatures will ultimately destroy oil yielding mainly graphite and methane. Eventually, even commercial accumulations of methane are absent. Each sedimentary basin has a characteristic hydrocarbon limit, beyond which drilling is futile. ECONOMICS OF DEEP DRILLING In 1973 there were 506 wells drilled deeper than 15,000 ft. at a cost of over half a billion dollars. The average deep well cost $1,107,000 compared with about $900,000 in 1972. Although deep drilling costs have increased rapidly in recent years, this has not always been so. From the early 1950's until about 1966 the average cost oscillated around $40 per foot, as shown in Figure 1. This was partly due to the remarkable improvements in drilling technology, particularly in the number of bits required for particularly in the number of bits required for deep drilling. This decreased from a high of around 200 bits per well in the late 1940's to only 38 bits per well last year. Since 1966 improvements in drilling technology have not been sufficient to offset rising costs, and for the ultradeep wells below 20,000 ft., the cost rise has been particularly steep. Today six wells can be drilled to 15,000 ft. for each well that is drilled to about 30,000 ft. as shown in Figure 2. There is no question that drilling in the 15,000 to 20,000 ft. range is justified. Last year 31% of the wildcats were successful, which is high by most standards. The real question is, how much deeper than 20,000 ft. can we drill profitably? profitably? From 1944 through 1958 the deepest production generally lagged behind the deepest well production generally lagged behind the deepest well by about 3,000 ft. as shown in Figure 3. In 1959, this gap began to approach 5,000 ft. and this year it exceeded 8,000 ft.

Abstract The paper briefly reviews, in the first section, the criteria, the methods and the technologies, that AGIP actually applies in planning and drilling deep wells in the Po Valley basin. The discussion, that regards this part, will be necessarily summarized, because a complete and detailed presentation of these subjects appeared recently in literature. In this occasion, anyway, it is worthwhile to recapitulate at least the main concepts, concerning:the methods, that allow accurate prediction and evaluation of the overburden, pore pressure and fracture gradients from the analysis and elaboration of seismic data, drilling parameter sand electrical logs;the criteria of application of this information to well planning, in particular for what adequate and justifiable selection of casing points, casing design, fracture jobs, mud and cement technologies etc., is concerned. In the second section, the paper describes in detail the field results of three particularly significative and among the deepest wells drilled by AGIP in the Po Valley. The cases discussed put into evidence the satisfactory agreement observed between well planning and field results, in spite of the depth, planning and field results, in spite of the depth, abnormally high pressures, temperatures, hole problems implied, that make the Po Valley basin among the most difficult and interesting areas in the world. Introduction Oil exploration in Italy has always to face remarkable technical problems due to the particularly complex geological situation of the country. This complex situation, of which the Alps and the Appennines are the most significative outcropping examples, continues also underground in plain areas, as in the case of the Po Valley basin. The Po Valley basin, with an area of 46,000 km2, a length or 400 km and a width varying from 80 km to 270 km, is the largest plain in Italy; it is crossed, by the Po river and is almost completely covered by a thick alluvium. The main deposition is formed by clastic sediments from Oligocene to Quaternary, originated by the erosion of ancient and recent relieves. These sands, marls and shales are lying on deeper Mesozoic carbonates, the most interesting of which, from the hydrocarbons point of view, are the dolomites of the Triassic "Dolomia Principale" formation. Up to the last decade, AGIP activity in Po Valley was essentially directed to Pliocene and/or Miocene targets; only recently, when new geophysical techniques of acquisition and processing of seismic data were introduced, the deeper Mesozoic targets started to be faced. At this point, AGIP had to solve such problems and situations as to be obliged to review most problems and situations as to be obliged to review most of criteria and methods, known from the traditional literature. Tn the 1970-72 period, sixteen wildcat wells were drilled at depths varying from 4,000 to 6,000 m; in 1972 the drilling of the well Malossa 1 led to the discovery of the first field in the Po valley basin producing from the "Dolomia Principals" formation. producing from the "Dolomia Principals" formation. The Malossa field is at present under development; thirteen wells have been already drilled or are under way to be completed on the structure, at depth from 5,500 to 6,500 m about. AGIP deep drilling programme, on the basis of the Malossa success, received a very strong impulse; up to now, more than 40 wells reached depths higher than 5,000 m.

Abstract Sichuan basin is the primary carbonate deposition basin in China, which is rich in natural oil and gas resources and has a very long drilling history. The geological conditions in the basin are very complex, which causes a lot of difficulties in deep drilling. Since the end of 1970's with the development of exploration and drilling in deep formation, a series of complicated technical problem in deep and ultradeep drilling have been well solved. During the recent years, a large number of deepwells and some ultradeep wells have been completed. The economic index of drilling technique has been largely improved. This paper foresees the forture development of deep drilling technique in Sichuan basin. Introduction Sichuan basin with an area of 180 thousand square kilometers and sedimentary rock of thickness about 6000–12000 m. is a basin with carbonate rocks as the main oil and gas bearing formations.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Drilling and completion costs in the Uinta Basin have been high for several reasons, mainly, 1) tough, abrasive formations, 2) long rig moves into the Basin, 3) weather, and 4) high inflationary rate. Other author have discussed these problems in detail. This report discusses some of the cost reducing practices which Gulf has used. The objective practices which Gulf has used. The objective has been to develop efficient, safe, drilling and completion practices. Savings of approximately 10 per cent have resulted even though the inflationary rate has been at a record high during this period. Introduction The Uinta Basin, located in Northeast Utah (Figure 1), came into recent drilling prominence in May, 1970, with the field prominence in May, 1970, with the field discovery, Shell-Miles No. 1. This well flowed, initially, at a rate of 1100 barrels of oil per day from an interval near 12,900 feet. Subsequently, 210 wells have been drilled and completed (Figure 2), by a drilling force varying from 25 to 40 rigs. Production has been principally from the Wasatch formation with a small amount being produced from the Green River formation. produced from the Green River formation. The producing trend stretches 40 miles northeast-southwest and is 10 to 15 miles in width. Daily production from this area has risen to approximately 62,000 barrels oil per day (Figure 3). DEPTH DIFFERENCES An earlier report by Findley in 1972 described drilling and other difficulties associated with operations in the Uinta Basin. At that time only two Gulf development wells had been completed. Currently, 37 development wells have been completed, with 6 of the 37 wells reaching depths ranging from 16,200–19,500 feet. The other 31 wells were drilled to depths ranging from 10,000 to 14,800 feet. Figure 4 indicates the reason for the differences in depth. This northwest-southeast cross-section, covering approximately 16 miles, shows Duchesne River, Uinta, Green River, Basal Green River, Wasatch and Cretaceous formations dipping northwest toward the axis of the Basin, while surface ground level is rising northwest, toward the Uinta Mountains. This combination provides more interval to penetrate to the provides more interval to penetrate to the northwest, accounting for increased depth across the field.

Abstract Deep wells, particularly exploratory tests, not only require detailed planning and precise execution but also other work activities to bring such wells to a successful conclusion. A management method consisting of planning, organizing, controlling and leading can be used to define the various activities necessary for successful deep drilling. Even though specific engineering aspects of such nulls are often unique to individual prospects, a general engineering philosophy applicable to deep holes can nevertheless be described. Introduction Deep oil and gas nulls, those wells drilled to a depth greater than 15,000' (4,600 m), once thought the domain of the venturesome independent and major oil company, are no longer unique. By now many companies have drilled sells to depths greater than 15,000'. In fact after leveling off at a plateau of approximately 400 wells annually since plateau of approximately 400 wells annually since 1970, the number of wells drilled below 15,000' dramatically increased by 62%, to 683 wells, in 1978. Although accounting for less than 1.4% of the total number of wells drilled in the United States, deep wells accumulated 4.8% of the footage drilled, utilized approximately 12% of the available rig time and incurred 13.3% of total expenditures. Deep exploratory wells amounted to 2.6% of all exploratory tests and accounted for 7.4% of exploratory footage. Significantly in 1978, nearly half of all deep sells mere classified as "exploratory" and realized a success ratio of better than 30%. Without a doubt, deep drilling, spurned by a good success rate and Federal cost incentives, is expected to increase at an accelerated rate. Consequently the success in drilling such wells, both from a mechanical standpoint and booked hydrocarbons, will greatly influence the growth and in some cases even determine the survival of many oil and gas companies. I. MANAGEMENT METHOD With deep drilling assuming an ever more important role in domestic oil and gas operations, the severe cost escalation which has occurred over the past years will became even more burdensome. Since the upsurge in drilling activity of the early 1970's average well costs have increased at a rate twice that of inflation. Fortunately this trend is slowing. The increase in drilling cost is expected to be only 40% more than the inflation rate in 1979. Nevertheless the average well in 1979 can be expected to cost 75% more than five years ago. Cost escalations in deep wells has been and probably will continue to be even more acute. In probably will continue to be even more acute. In 1978 the average cost per foot for deep wells, Table 1, increased 18%, a rate 40% greater than the average well. Part of this may lie in the continued rapid increase in costs of certain well equipment and services more significant to deep wells than shallow sells. Although casing and tubing costs, the greatest single well cost item, have increased at approximately the national inflation rate, other large expense items of deep sells - drilling mud, evaluation services, drilling bits and wellheads - have increased at a substantially higher rate. More significantly perhaps, the substantial increase in deep well activity has created an appreciable "dilution of talent", resulting in an average loss of deep drilling expertise and efficiency. Without a doubt these effects have been felt by operators, service companies and contractors. The increasing cost trend and noticeable loss of efficiency must he greatly abated if deep drilling is to continue at a rapid pace.

Abstract In the Anadarko Basin, well development costs increase exponentially with depth. Average porosities for both sandstone and carbonate reservoirs decrease with depth in a predictable manner. Normal pressure and temperature gradients and a general porosity-water saturation relationship can be used to establish gas in place for reservoir rock at various depths. Recoveries can be calculated using typical permeability versus porosity data. A base case with 10 feet of net sandstone pay at a depth of 10,000 feet was used for comparative purposes. A 0.15 probability of this case yields an expected discounted cash flow rate of return of 15%. At depths of 15,000, 20,000 and 25,000 feet, sandstone pay thicknesses of 29, 89 and 297 feet are required to match the base case in terms of volume of gas in place per dollar spent. If recovery rates are considered, these thicknesses must be increased to 34, 128 and 670 feet respectively, to maintain a 15% rate of return. Similar relationships are indicated for carbonate reservoirs. Introduction The purpose of this paper was to compare economic for wells in the Anadarko Basin for depths varying from 10,000 to 25,000 feet. Because of the low incidence ooil occurrence below 10,000 feet, only gas wells were considered. For comparative purposes, economics for a base case gas well at a depth of 10,000 feet were run. Economics were then calculated for gas wells at depths of 15,000, 20,000 and 25,000 feet. The following data were used:constant gas price, gas gravity and operating expenseexisting Anadarko Basin data correlating porosity with depthnormal temperature and pressure gradientsgeneral variations in water saturation and permeability with porosity Pay thicknesses were varied to maintain constant economics at depths of 10,000 to 25,000 feet. Economics were considered both from the standpoint of maintaining a constant cost per Mcf of gas in place and also a constant cost per discounted Mcf of gas recovered. For this paper, the term "discounted Mcf" refers to the gas volume which is derived from projecting production rates with a deliverability model projecting production rates with a deliverability model and discounting those predicted volumes of gas with 15% present value factors. This approach considers both recovery efficiency and the present value concept of money. BASE CASE For this case, the following data were used:10,000 ft depth10 ft sandstone pay400 acre drainage area0.65 gas gravity (no condensate)4340 psia original pressure207 degrees F reservoir temperature12% porosity27% water saturation0.5 md permeability-4 skin factor215 psia pipeline pressure$475,000 producing well cost (1/3 equipment;2/3 intangibles)$380,000 dry hole cost$2.07/Mcf gas price$20/day operating expense50% tax rate (federal income, production and ad valorem taxes)3/16 royalty20 year double declining balance depreciation

This paper was prepared for the 1972 Deep Drilling Symposium of the Society of Petroleum Engineers of AIME to be held in Amarillo, Tex., Sept. 11–12, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A type prospect in the "Deep Anadarko Basin" is described and its profitability is measured in terms of Discounted Cash Flow Rate of Return. Certain of the prospect's parameters are varied between limits thought parameters are varied between limits thought to be reasonable for the area and the results of the variations compared by the use of the same profit indicator. The use of the type prospect, or "Base Case," in the evaluation of other prospects is illustrated. It is evident in prospects is illustrated. It is evident in all the analyses made that gas price increases are the only available means of increasing profitability to the level necessary to solve the present gas shortage. Introduction The purpose of this paper is to present a general overview of the existing development of natural gas production in the deeper portion of the Anadarko Basin of Texas and portion of the Anadarko Basin of Texas and Oklahoma with particular emphasis on the economics of the play; past, present, and future. Such a study is thought to be worthwhile at this time to serve as an indicator of whether or not a continuing search for gas supply in the area can be maintained on its own merits. The viability of the effort depends on its ability to generate the income level necessary to support the investment required. Any economic analysis must consider the cash return with respect to the cash expended. When such an analysis is made of a particular venture, in this case the search for and development and marketing of natural gas, then the income and expense items must be broken down into their component parts and each par examined as to its relationship to the total. It should be noted at this point that the detailed examination of the economics of the area has been made from the point of view of the industry, not from that of any of its ma facets. All expenditures, whether made for leasing, geophysical work, drilling, production, or employee benefits are charged to production, or employee benefits are charged to investment. Any income item, regardless of source, is credited to the return of that investment.

This paper was prepared for the 1972 Deep Drilling Symposium of the Society of Petroleum Engineers of AIME to be held in Amarillo, Tex., Sept. 11–12, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The safe economical drilling of an ultradeep well depends upon several interrelated factors. Drilling fluid is one of the key factors. It contributes to, or eliminates, hole problems. It is a tool of the hydraulic program, influences bit performance and rate program, influences bit performance and rate of penetration. It is a vital communication link with the dictates of the hole. Its performance and maintenance contributes directly performance and maintenance contributes directly to safety and economy. It must be designed to perform with stability and predictability as an perform with stability and predictability as an integral tool in the total drilling operation. To design an interrelated program for casing, mud, bit hydraulic, monitoring, and drilling; a pore pressure-fracture gradient profile for the drill site must be developed. profile for the drill site must be developed. This requires the compilation, cross checking, and verification of all possible data including records from seismic, bits, DST, production, wireline logs, recaps, and well histories. The distilled pressure-fracture information is then plotted by depth and formation against pressure plotted by depth and formation against pressure expressed as mud density. The profile will indicate desirable casing seats and show maximum-minimum mud density requirements throughout the hole. Add hole size requirements and formation characteristics and the profile is the basis for the bit and hydraulic profile is the basis for the bit and hydraulic programs. Hole size, geometry, and hydraulics programs. Hole size, geometry, and hydraulics determine any special rheological considerations. Low pressure permeable zones determine filtration characteristics. Water or chemically sensitive formations, contaminants, and temperature determine mud type. Thus, anticipated conditions determine the physical and chemical requirements of a drilling fluid. The mud that will most satisfactorily give these requirements determines the type system needed. The monitoring program will continually confirm or immediately note any deviation from the expected profile. Mud properties should be closely monitored, as well as flow rates, mud volume, drilling variables, pressure losses, and geological data. Changes in these variables can indicate adjustments to be made in mud properties to insure best performance characteristics for prevailing conditions. Introduction In recent years the design of a mud program as a key part of the drilling systems program as a key part of the drilling systems has been given considerable attention. This is especially true in regard to maximum-minimum density requirements.

This paper was prepared for the 1972 Deep Drilling Symposium of the Society of Petroleum Engineers of AIME, to be held in Amarillo, Texas, September 11–12, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Many deep well development drilling programs have now been in progress for ten years programs have now been in progress for ten years or more. During this time it has been necessary to modify previously existing drilling techniques and create new procedures in order to drill deep wells economically. Costs related to deep drilling have increased substantially during this period. As a result it is primarily through the use of improved technique primarily through the use of improved technique coupled with advancements in drilling equipment and materials that has enabled operators to these cost increases. Continual improvement mandatory in order to overcome the financial burden placed on the operator by constantly rising costs of materials and services. Introduction Deep well development drilling became reality almost ten years ago with the discovery of the Gomez field in Pecos County, Texas. The definition of deep drilling for the purpose of this presentation will be any well drilled below 20,000 feet. It is readily apparent that a revision of this definition will be necessary in the future. During this ten year period of deep development drilling, it has been necessary to continually improve drilling equipment and techniques in order to economically develop the deep fields which have been discovered. Many techniques which are now utilized routinely were either not acceptable or unavailable ten years ago. The purpose of this paper is to point out the more purpose of this paper is to point out the more important refinements in drilling technique which are now acceptable to many operators. DRILLING RIG EQUIPMENT During this first decade of deep development drilling, changes made in the basic drilling rig which have improved operations have been relatively minor. It is commendable that the manufacturers and the contractors had rigs ready for deep drilling before the demand for such rigs became as evident as it is now. Of course, the rigs now drilling deep wells have been continually upgraded. Available horsepower has been increased on many rigs. This has been done primarily because of increased power requirements primarily because of increased power requirements for pumps. Mud pits are now larger in order to facilitate treating and maintaining the large volumes of drilling fluids necessary at depth.

Abstract The drilling contractors of the Permian Basin have been hard-pressed to meet the demand for 20,000-ft drilling rigs since the discovery of the prolific gas reservoirs in the deep Delaware Basin. The demand came at a time when the contractors of the area had felt the economic squeeze to the point that they did not have the capital to purchase new rigs for this class of work. Now, three years later, it is obvious that the contractor has met this demand. By maximum utilization of his existing equipment, he has spent a minimum of money. This has required a careful analysis of each of the major rig components to determine what demands a 20,000-ft well will impose. New equipment has been purchased only as a last resort and most of the rigs in service today on these wells are the products of a process of selective up-grading of older rigs. By discussing each of these rig components, this paper will show what is required, when and where the horsepower is needed, and how and why the rigs that are working today have been assembled. The contractors have proven that these rigs are adequate and capable of successfully drilling deep wells. Introduction In Dec., 1965, there were 23 rigs in the Delaware Basin at work on wells scheduled to drill below 20,000 ft. An investigation of these 23 rigs surprisingly would show that just one of this number is a completely new rig. The remainder, although perhaps carrying a new company number, are the results of a process of selective up-grading of used equipment by the contractor.