bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Stimulation Technique Proven Effective in the World's Biggest Deep Gas Producer
Authors: Crenshaw P.L. , Joines B.R. 
Published: December 2007

Abstract
Previous results of stimulation treatments in the deep Ellenburger gas fields of West Texas have provided less increase than predicted by the computer when designing these treatments. Major contributing factors are (1) inability to input an accurate relative permeability of the fractured vugular formation to the stimulation fluid, (2) inability to control leakoff of treating fluids in this type rock, (3) inadequate penetration of live acid into the formation.
It can be shown on the computer that the effect of a fractured carbonate rock versus a nonfractured one can account for the difference between actual and previously calculated treatment results. A case history is given in which a new design technique is used in combination with effective leakoff control mechanisms to provide (1) better well productivity than previously experienced and (2) treatment results that agree with calculated predictions.

Introduction
The purpose of this paper is to discuss the theory and application of the stimulation program performed on the well that was program performed on the well that was advertised as the "Worlds' Largest Gas Producer". It is very important to remember that the treatment was not solely the reason for the outstanding productivity of the well. Just as important are the careful planning and application of the drilling and completion of the well. Also, the well was an excellent candidate for high production rates which were predicted prior to the treatment. Nevertheless, the evolutionary history of stimulation treatments in this area shows that there are significant differences in the results obtained by different treating techniques. Presently, the method described in this paper Presently, the method described in this paper does appear to be best.
The subject well is located in the southern part of Pecos County, Texas along the southern boundary of the massive Delaware Basin, (Fig. 1). The well is located in the Elsinore Multipay Field which is one of several fields whose principal gas producing reservoirs are in the Devonian, Fusselman, and Montoya Formations. One or all of these formations are productive in the J.M. Field, the Puckett Field, the Oates Field, and the Cayonosa Field, which are within a 50 mile radius of the Multipay Field. The gas produced in these fields has an appreciable produced in these fields has an appreciable content of Carbon Dioxide. The characteristics of the productive formations in the Elsinore Multipay Field are similar to most deep carbonate formations that contain hydrocarbons.
Pumping Deep Wells With a Beam and Sucker Rod System
Authors: Byrd J.P. 
Published: December 2007

Abstract
By using advanced predictive methods, high strength rods, optimum pumping mode, and unit geometry, the depths from which beam and sucker rod pumping systems effectively lift fluid can be significantly increased. Following is a discussion of some of the factors involved.

Introduction
Reliable estimates have suggested that over 80% of the world's artificially lifted wells are produced by a beam and sucker rod system. Some of the factors contributing to the sustained use of this traditional pumping method are:its simplicity,reliability,efficiency,flexibility,economy,relatively low maintenance, andhigh resale value.
Besides these favorable considerations, recent forward strides have also been made in the design and manufacturing technology of the system's component parts.
For years, much of this popularity existed for shallow-to-medium depth applications, but when substantial volumes were to be lifted from deep wells, the historic beam system was often passed over in favor of more sophisticated, less passed over in favor of more sophisticated, less reliable and efficient artificial lift methods.
In the past, inability of sucker rod systems to produce high volumes from deep wells resulted from several factors:the components of the system were unable to transmit sufficient power to the bottomhole pump over sustained power to the bottomhole pump over sustained periods, without periodic failure;a lack periods, without periodic failure;a lack of understanding of the complex behavior of the sucker rod system, and the involved nature of the reservoir, its fluids, and their inflow performance; andattempting to superimpose performance; andattempting to superimpose a new beam and rod system design on the constraints of an existing application.
Because of its inherent reliability, economy (in an energy short world), improvements in technology, and better understanding of reservoir and system behavior - the beam and sucker rod system is, today, capable of producing ever greater volumes from deeper producing ever greater volumes from deeper and deeper wells. Properly designed and operated pumping systems are capable of producing the following: producing the following:DEPTH VOLUME(ft.) (B/D)
10,000 1,0009,000 1,0508,000 1,1507,000 1,2506,000 1,5005,000 1,850
Although not all of these maximum fluid volumes have necessarily been realized and documented, in field practice, some have, and current technology makes their attainment both feasible and practical.
Well Test Analysis of Hydraulically Fractured Gas Wells
Authors: Dowdle Walter L. , Hyde Paul V. 
Published: December 2007

Abstract
Hydraulic fracturing has been used extensively over the past fifteen years to stimulate low permeability oil and gas wells. A considerable permeability oil and gas wells. A considerable amount of fractured well performance theory has accumulated during this period. Transient drawdown solutions for vertically fractured liquid wells based on numerical simulation were published in 1964. These solutions established the influence of vertical fractures on transient pressure buildup and drawdown testing. Others have investigated well tests of vertically fractured gas wells using both analytical and numerical models. Recent studies have provided new information for type-curve matching of pressure data obtained from fractured (vertical and horizontal) wells. The objective of this paper is to illustrate the application of numerical simulation in evaluation of fracture stimulation of gas wells. The previously published interpretation methods, such as pressure buildup and drawdown analyses and type-curve pressure buildup and drawdown analyses and type-curve matching, form an extremely important part of the complete analysis. Better and more comprehensive well test interpretation can often be obtained by using the so-called conventional methods and numerical modeling together.

Introduction
Prats, et.al., originally developed analytical solutions for the performance of vertically fractured reservoirs for the compressible fluid case. They considered both the constant terminal pressure and constant terminal rate cases. In the case of constant rate, however, the early-time pressure transient solutions were not investigated. In 1964, Russell and Truitt published transient pressure solutions for vertically-fractured oil or water wells based on numerical simulation. From their solutions they developed methods of analyzing pressure buildup and drawdown tests with conventional plotting techniques. Clark later applied the Russell-Truitt results in analysis of water-injection well falloff data. Analytical solutions and example applications for vertically fractured wells which produce slightly compressible fluids also were presented by van Everdingen and Meyer.
More recently Gringarten, et.al., have reviewed the work of previous authors and published new solutions especially useful for published new solutions especially useful for type-curve analysis. They illustrated the use of their results (for wells with either vertical or horizontal fractures) in a companion papers.
Straight-Hole Turbodrilling
Authors: Enenbach Joseph H. 
Published: December 2007

Abstract
The purpose of this paper is to present the relevant factors surrounding the use of turbo drills for straight-hole applications. The presentation begins with the developmental background and mechanics of the turbine as well as the necessary conditions under which it must operate. Subsequently, the hydraulic considerations, diamond bit selection and standard operating procedures are examined. Finally, the procedures are examined. Finally, the economics of the turbine decision is reviewed.

Introduction
The oil industry has been ever searching for a less expensive and more effective method of reaching the drilling target. One approach has been to design and test a variety of down-hole motors. These motors have included mud-driven turbines, positive displacement mud motors and electrically powered motors. Of these, the most powered motors. Of these, the most attractive have been the turbines and the positive displacement motors. Since the mud is already being used to remove the cuttings, its presence makes it a likely candidate for providing power to a drilling motor.
Turbines are not new as far as their application to drilling is concerned. The possibility of using a turbine as a down-hole motor to power the bit was first recognized in 1873 when C.G. Cross was issued a U.S. patent. Conventional rotary drilling was later patented in 1884, but further patented in 1884, but further development of the turbine in the Western world was sporadic. Various turbo drill designs were tested but the main failing of American designs was the excessive bearing failure brought about mainly by the action of abrasive drilling fluids. The Russians surmounted this problem in the 1950's by developing rubber compound thrust bearings which could tolerate the abrasiveness.
Problems Associated With the Drilling and Completing of Morrow Sands in Western Oklahoma
Authors: Calverley Larry S. 
Published: December 2007

Introduction
Deep, high-pressure Morrow sands in the western Oklahoma portion of the Anadarko Basin indicate the area's potential to become one of the more prolific natural gas producing areas in the continental United States. In the past several years, there have been a number of major deep Upper-Morrow gas discoveries in the Oklahoma counties of Beckham, Roger Mills, and Washita. Fig. I illustrates the major Upper Morrow fields in the three-county area.
El Paso Natural Gas Co. has been engaged in an active exploration program in this area during the past 6 years. This paper is based on the company's accumulated drilling experience in the area combined with the knowledge and experience of drilling contractors, service companies, and other operators active in the area. The area is unique in that almost every conceivable problem known to the drilling industry can occur during the drilling and completing of a single Upper Morrow well. This paper will summarize a few of the most frequent and most troublesome problems encountered by El Paso Natural Gas Co. in western Oklahoma. This paper will also discuss methods used by the company to prevent, overcome, or alleviate the problems.

SUBNORMAL AND ABNORMAL PRESSURES
The most important and most critical drilling problem in the western Oklahoma area of the Anadarko is abnormal pressure. All Morrow tests in the area must be designed basically to hold formation pressures ranging from the equivalent of 16.3-ppg to 18.1-ppg gradients. To add to the problem, in the area there are many fractured loss circulation zones with fracture pressure gradients of lower than the gradient of saturated salt water. Also, many areas of regressive fracture gradients add to the complexity of selecting the proper casing points. points. Fig. II is an equivalent pore pressure plot of the El Paso-Hunt Cross No. 1 located in Section 22, T-13-N, R-24-W in Roger Mills County, Okla. This well was the discovery well of the West Cheyenne field. The actual casing program is also shown. The area has normal program is also shown. The area has normal pressures (0.433 psi/ft) to an approximate depth pressures (0.433 psi/ft) to an approximate depth of 10,500 ft. At 10,500 ft, the gradient starts building rapidly, reaching 13.8 ppg at approximately 11,000 ft in the Granite Wash section. Below this interval, formation pore pressures continue steadily increasing throughout the Granite Wash and Atoka sections, reaching 15.5-ppg equivalent at 15,000 ft.
Guideline of Artificial Lift Selection for Mature Field
Authors: Naguib M. A. , Bayoumi A. , El-Emam N. , El Battrawy A. 
Published: December 2007

Abstract
Ras Fanar is located in the western part of the Gulf of Suez about 3 km east of the city of Ras Gharib, Egypt (Fig. 1). Production commened in January 1984 and a peak production rate of 20 MSTB/D was achieved in January 1988.
Due to the relatively low reservoir pressure for Ras Fanar field, some of the wells experienced lifting problems at water cuts above 20% requiring nitrogen lift to restore intermittent production. Clearly, some sort of artificial lift was needed in order to restore the production rate to the normal levels and to maximize the ultimate recovery.
The decision of which artificial lift method to use is very important to the long-term profitability of the field. An improper selection of artificial lift can reduce production and increase the operating cost substantially. Once a decision has been made on the type to install on a well, it can be rarely altered whether or not the method selected was and still is the optimal for the existing conditions.
This paper presents the screening criteria on the different artificial lift techniques and discusses why the choices were confined to ESP's and gas lift as the most suitable techniques to be applied in the field. The paper explains the two different alternatives, and studies the technical consideration behind each.
Reservoir simulation model was used to predict the performance and the ultimate recovery either naturally or using ESP and Gas Lift. An economical evaluation for both cases was then conducted taking into considerations both capital and operating costs of each opinion.
Single Fracture Treatment on Dual Zones of Low Resistivity / Low Contrast Pays in Java Sea - ONWJ Field Cases
Authors: Susilo R. Yoliandri , Zailani Achmad , Rich David A. 
Published: December 2007

Abstract
This paper uses case histories to evaluate fracture treatments for developing low resistivity, low contrast (LRLC) formations in the Offshore North West Java (ONWJ) field, Java Sea, Indonesia. LRLC formations are found throughout the ONWJ field but were originally interpreted as non- productive formations. Field production declines resulted in a review of secondary opportunities and as a result of this study these LRLC pays were identified as potential development opportunities. This paper, through the use of case histories, focuses on the development of two LRLC zones, L-33 and L- 35, in the Lima Area of the ONWJ field and shows how, through the use of fracture treatments, these zones could be developed economically.
To date, a total of 11 wells have been worked over and fracture stimulated to develop the L-33 and L35 zones with varying degrees of success. Oil production increases of up to 1000 BOPD have been observed. These successful results have brought new opportunities for developing similar zones within the ONWJ field. This paper also reviews and discusses the post fracture analysis used to optimize these treatments.
A treatment technique has also been developed for developing the zones that are located above first packer without pulling out the completion string. This technique will result in significant cost saving compared with conventional frac jobs.
Upper Morrow Development, Reydon Field
Authors: Borger J.G. 
Published: December 2007

Abstract
Development drilling for gas from Upper Morrow sandstones in the Reydon Field, Roger Mills County, Oklahoma, and Hemphill County, Texas, has yielded a 60% success ratio. Development risk is high because these Upper Morrow sandstones exhibit a complex prodeltaic depositional environment. Reservoir prodeltaic depositional environment. Reservoir pressures exceeding 12,500 psia and temperatures pressures exceeding 12,500 psia and temperatures of + 280 degrees F. in the 15,000' range also create high drilling costs. Inasmuch as potential reserves are estimated to be greater potential reserves are estimated to be greater than 15 Bcf per well, development of these reservoirs still offers excellent economic return for investors.

Introduction
Deep drilling for hydrocarbons in the Anadarko Basin provides the petroleum industry with a new frontier for the discovery and addition of much needed fuel reserves. However, geological and operational risks associated with newly found deep reservoirs are severely magnified such that wildcat success does not necessarily assure typical development success. Development of gas from Upper Morrow sandstones in the Reydon Field is an example of successful drilling in spite of many problems associated with the geology and operations.
The Reydon Field exhibits a complex depositional environment of Upper Morrow sandstones which makes definition and predictability of the reservoir rock difficult. predictability of the reservoir rock difficult. In addition, Upper Morrow reservoirs at Reydon are abnormally high pressured, exhibit higher than normal temperatures and contain scale producing fluids which create hostile drilling producing fluids which create hostile drilling and production conditions. Proven and potential reserves, however, outweigh the increased risk and have afforded an excellent investment opportunity for those willing to assume this risk.

GENERAL
Location - Reydon Field is located in T 13 and 14N, R 26w, Roger Mills County, Oklahoma west and west southwest of the townsite of Reydon, Oklahoma and extends across the state line into the eastern sections of Block Z-1-ACH and B and H and W Survey and Block C-G and M and MB and A Survey, Hemphill County, Texas. The field has been variously designated West Reydon, Northwest Reydon and Viking Field (Hemphill County, Texas), but for purposes of this paper the entire area is referred to as the Reydon Field.
Juggling versus Planning - A Constraint Management Approach to Planning and Teamwork
Authors: Musolino V. J. , Mackey P. A. , Roberts Geoffrey A. , Min Peter A. 
Published: December 2007

Abstract
The South Australian Business Unit of Santos Ltd is a significant producer of sales gas. A large program of work is undertaken each year to ensure that gas markets are met.
The process of connecting wells for production contains in excess of 1600 activities in any one year. This includes both office and field activities. Ensuring the earliest maximum gas- on-line, whilst achieving the most effective and predictable utilization of finite resources is vital.
The Petroleum Engineering department developed a unique planning methodology system, which models the gas development program in real time.
The new process has yielded significant benefit in resource and materials utilisation and allowed substantial cost savings.
The previous scheduling approach often compromised budget production forecasts through projects failing to meet agreed timelines. It suffered from the absence of a robust tool to model and test the validity of the original assumptions before commitment to the well development program. It was also unresponsive to change.
The new system models the deployment of a variety of resources and also tracks critical milestones in the undertaking of each project. The system works to achieve earliest on-line gas with minimal resource and material wastage.
This paper demonstrates that it is possible to achieve greater work efficiencies, project throughput and manage a large number of concurrent projects competing for finite resources, through effective management and scheduling of a finite level of resources.
Combined ESP / Auto Gas Lift Completions in High GOR / High Sand Wells on the Australian Northwest Shelf
Authors: Aitken K. J. , Allan J. C. , Brodie A. D. , Holmes J. D. 
Published: December 2007

Abstract
The paper presents experience with an electric submersible pump (ESP) / auto gas lift completion design. The design has been developed to overcome the production engineering challenges which have been encountered following the commencement of production from the Stag oil field.
The flow from the horizontal section of the wells has a high gas fraction, continuously slugs with a very short frequency, and carries large volumes of sand following the onset of water production. In addition, the reservoir pressure has depleted more rapidly than had originally been expected. These characteristics combine to represent one of the most challenging environments in which a field can be developed using ESP's.
The paper describes the evolution of the completion design, which allows natural flow via either the tubing or the annulus, ESP lift via the tubing augmented by auto gas lift via the annulus, or conventional compressor-driven gas lift via the annulus. The measures taken to overcome poor ESP run life as a result of sand-laden slug flow are also described. Finally, operating experience with the improved completions is reviewed.
The improved completion has been installed in six wells. In one well, a definitive incremental production rate of 1700 stb/d (60%) was achieved. The other wells are either new wells, or have had other remediation measures applied e.g. additional perforations. It can be demonstrated from their behaviour, though, that incremental production of 40-80% is the direct result of the improved completion design. In addition, ESP run life has been improved by more than 100%.
Real-Time Data Analysis While Drilling Provides Risk Management for Both Geological and Geometric Uncertainties in the Sotong K2.0 Reservoir
Authors: Md Zin Che Lah , Sering Lancelot , Bakar Azlee Abu , Sundal Eva , Daudey Jan 
Published: December 2007

Abstract
Modern communication systems can transmit data from the wellsite to shore in real time, allowing full utilization of advanced drilling technology, 3D seismic and geological earth modeling. While drilling, real-time data can then be analyzed by all available experts to refine well plans and geological models for optimized well placement.
This case study demonstrates how the application of this technology optimized production and drainage efficiency through the successful drilling of several horizontal wells with complex objectives. The methodology clearly has definite application in field development planning and reservoir simulation studies.
The Sotong 4 well is one of five planned multilateral horizontal wells to drain the Sotong field K2.0 reservoir in Malaysia. The 14-m oil column is overlain by a large gas cap and has a moderately active aquifer. In-house studies on exploration wells confirm that gas coning will result in rapidly decreasing oil production and that a conventional field development would exhibit marginal economics.
Reservoir simulation defined the optimal horizontal well placement as 2 m above the OWC, within a ±0.5-m tolerance of TVD. Industry survey error models clearly show that this tight geometric control is not achievable using MWD survey data alone and additional techniques are required to control the geometric TVD error.
An empirical model was developed from offset well data, allowing LWD data to be used to position the wellbore within the oil column. The TVD could then be determined in real time and the well trajectory refined.
All three laterals of Sotong A4 were drilled within ±0.15-m TVD tolerance and production tests on Sotong A3 proved the validity of the model. The preparation and use of the geological model, as well as the challenges of landing and drilling the horizontal section, are discussed, with particular emphasis on survey error management and steering decision- making.