bluuebunny/crossref_metadata_2025 huggingface dataset:
Overcoming Completion Challenges With Interventionless Devices - Case Study - The "Disappearing Plug"
Authors: Larimore David R. , Huggins Jeff , Lyngaas Kjell Harry , Robb Ewan , Bach Terje
Published: December 2007

The ongoing need for greater operational cost efficiency has encouraged oil companies to seek new methods that can simplify completion processes and reduce the number of required well interventions. This focus has resulted in new challenges for engineering/manufacturing and service companies to develop multi-functional equipment. To meet the challenges, a new generation of completion equipment with capabilities that would have been considered impossible ten years ago has been introduced to the oilfield. This equipment has been designed to not only reduce the number of interventions normally required in traditional completion scenarios but also to meet challenges of safety and reliability that can surpass the cost of contingency measures should the product fail.

The development of one such device, the "disappearing plug," which serves as a plugging device for setting a hydraulic-type packer, will be the focus of this paper. When run in with the completion, the tubing will fill automatically through an auto-fill device, and then, will close during one of the pressure cycles. The fluid-expendable plug material disintegrates on the last pressure cycle, which allows full-tubing-drift production and eliminates the need for a slickline or coiled-tubing run to retrieve a plugging device as would be the case with conventional methods.

While the industry average for successful installation of interventionless devices has still not reached the sought-after 100% reliability, when these concepts have been successful, the expected economic job goals have been surpassed. When successful in offshore, horizontal, and/or high angle wells where slickline or coiled tubing intervention after completion is significantly more costly, these interventionless technologies have proven to be even more beneficial.

The paper will discuss development of the plug, some of the failures that occurred, how these difficulties were addressed, and finally, will discuss several recently run installations. These clearly show the extent of the economic benefit that can be realized.

Disappearing plug technology currently improves economics by eliminating the need for slickline and coiled-tubing interventions in plugging operations. When setting hydraulic packers, this not only reduces operating costs but also the risks associated with interventions and plug failures. One of its most significant contributions, however, becomes apparent when considering the future trends of the industry — interventionless and intelligent well technologies. The disappearing plug will undoubtedly play an important role in the actualization of these future well trends.
Quality Control of NMR Logs
Authors: Stambaugh Brian , Svor Rick , Globe Mike
Published: December 2007

Nuclear Magnetic Resonance (NMR) Logging has gained widespread acceptance over the past decade. Those using NMR data need assurance regarding the quality of the data and the interpreted product. This is particularly true as NMR replaces other logging devices and is of paramount importance when NMR is run as a standalone service. NMR applications require proper job planning and acquisition for successful data processing, interpretation and integration with conventional logs. Quality control procedures are particularly important during data acquisition and during the creation of integrated computed products. This paper seeks to provide a reference for quality control of NMR data at acquisition and during subsequent interpretation. Examples are shown that demonstrate the importance of quality control related to data acquisition and processing. Quality assessment is divided into three areas; 1) Adherence to service company standards for calibration, tuning, and raw data quality. 2) Repeatability of NMR results. 3) Coherence of data with other available data. Respective of these three areas, some simple guidelines for quality assurance of NMR data and products are presented.
Gravel-Pack Isolation Squeeze for Plug-Down Recompletion
Authors: Fleming J. J. , Boyd S. R. , Wolverton D. M.
Published: December 2007

This paper presents a case history of a plug-down operation using a coiled tubing unit to perform a contaminated cement squeeze to seal a gravel-packed interval. This procedure maintained unrestricted tubing access, without milling, for wireline tools to perforate a lower bypassed zone of interest. A three-component or trimodal microcement-based slurry isolated the gravel pack and completion assembly. Standard cements, polymer gel systems, and conventional microcement slurries have not been shown to adequately address gravel-pack squeeze operations of this type. Incomplete placement and differential pressure during production are primary causes of failure. Furthermore, care must be taken during the coiled tubing contaminated squeeze procedure to minimize the risk of overdisplacing or contaminating the slurry once in place. This paper provides information to aid in the design and execution of gravel-pack squeeze operations, including water control treatments, zone abandonment, and through-tubing recompletions.
Permeability Estimation Using Hydraulic Flow Units in a Central Arabia Reservoir
Authors: Al-Ajmi Fahad A. , Aramco Saudi , Holditch Stephen A.
Published: December 2007

Knowledge of permeability is critical to developing an effective reservoir description. Permeability data can be obtained from well tests, cores or logs. Normally, using well log data to derive estimates of permeability is the lowest cost method. To estimate permeability, we can use values of porosity, pore size distribution, and water saturation from logging data and established correlations. One benefit of using wireline log data to estimate permeability is that it can provide a continuous permeability profile throughout a particular interval.

This paper will focus on the evaluation of formation permeability for a sandstone reservoir in Central Arabia from well log data using the concept of Hydraulic Flow Units (HFU). Cluster analysis is used to identify the hydraulic flow units. We have developed a new clustering technique that is unbiased and easy to apply. Moreover, a procedure for determining the optimal number of clusters that should be used in the HFU technique will be introduced. In this procedure, the sum of errors squared method was used as criterion for determining the required number of HFU’s to describe the reservoir.

In our work, the statistically derived hydraulic flow units were compared with the core description made at the well site by a geologist. The grain size classes from core description match very well with the statistically derived clusters from the HFU method. Our results indicate that hydraulic flow units correspond to different rock types in this Central Arabian Reservoir.

Of course, direct measurement of rock properties using cores is the ideal method to determine HFU’s. However, because the costs to cut and analyze cores are so high, few core measurements are routinely available. Hence, it is crucial to extend the flow unit determination to the un-cored intervals and wells. The relationship between core flow units and well log data was established by non-parametric regression in cored wells, and then was used as a tool to extend the flow units prediction to un-cored intervals and wells.

Permeability estimation using the HFU method was extended to un-cored wells by implementing the Alternating Conditional Expectation (ACE) algorithm. ACE provides a data-driven approach for identifying the functional forms for the well log variables involved in the correlation. The reservoir porosity vs. permeability relationship was represented with single equation by using the different HFU’s as indictor variables. Permeability profiles generated by HFU’s using well log data agree with core data.

A computer program was developed to perform hydraulic flow unit analysis. In the computer program, three main processing options were integrated, which are: sensitivity runs are made to determine the optimal number of HFU’s;the analysis is then based on the optimal number of HFU’s (or any user-defined number of HFU’s); andregression analysis is performed using the different HFU’s as dummy variables to predict values permeability.
Study of Refracturing Results in the Clinton Sand Formation
Authors: Greene Jack
Published: December 2007

Decline curves (production vs time) were drawn and evaluated in an effort to determine the results of restimulation work performed in the Silurian Clinton Sand Formation, east central Ohio area.

A total of seventy-one oil wells were hydraulically fractured between 1972 and 1975. Of these wells, seven had to be plugged and abandoned due to problems resulting from the restimulation work.

The average increase production due to restimulation was 4,000 bbls per well.

Introduction

This paper concerns itself with an evaluation of seventy-one oil wells restimulated by hydrofracing. The type of wells restimulated consisted of uncemented, shot wells, uncemented, fractured wells and cemented, fractured wells. The Oxford oil Company did this work between the years 1972 and 1975.

In this paper four case studies are used to evaluate the results by the different types of frac jobs. In selecting a particular well for case study examination, several factors must be considered. They are (1) volume of water injected; (2) type of completion; (3) type of initial stimulation; (4) past production history; and (5) geographic location. The wells in the case studies are classified according to the volume of water used in the restimulation.Less than 1,000 bbls1,000 bbls—2,500 bbls2,500 bbls—5,000 bbls5,000 bbls—10,000 bbls

Decline curves (production vs time) were drawn and analyzed to determine the ultimate recovery and economic limit of each reworked well.

For a successful rework, several factors must be completed.Clean out wellboreProtect casing against high pressure (if necessary)Increase fracture size and lengthWellbore must be clean before tubing run
Minas Surfactant Field Trial Tests Two Newly Designed Surfactants with High EOR Potential
Authors: Bou-Mikael Sami , Asmadi Faisal , Marwoto Danny , Cease Cedric
Published: December 2007

Caltex Pacific Indonesia (CPI) recognizes the enormous potential that a large scale tertiary enhanced oil recovery (EOR) project like Light Oil Steam Flood or Surfactant Flood can have on extending the operations in Minas oil field well into the 21st century. With 4.5 billion barrels of remaining target oil, a successful tertiary EOR process will have a significant economic impact on future operations. Tertiary projects are capital intensive and carry a high degree of risk, however, decision analysis (DA) studies for Minas indicate they have tremendous upside potential. In depth EOR screening identified two major processes for potential application in this high temperature, shallow reservoirs: Surfactant Flooding and Light Oil Steam Flooding. A successful Surfactant Field Trial in Minas will pave the way to potentially implement the process in several CPI fields in the Central Sumatra Basin.

The Minas Surfactant Field Trial is a unique project where two new low-cost surfactant systems, Lignin II and Synthetic Petroleum Sulfonate, have been specifically designed for Minas reservoir conditions. Lab tests indicated significant and comparable recovery from both systems in Berea and field cores. They are ready to be tested in the field for the first time.

Four different polymers, designed to provide a favorable mobility ratio in displacing the surfactant, will also be tested to select the most cost-effective system for Minas' high temperature environment. The purpose of the Field Trial is to validate the lab results, reduce the range of technical and economic uncertainties associated with recovery efficiency and field operations, and select the most cost-effective surfactant for field scale application.

The Surfactant Field Trial area is a 4.3 acre, 5-spot pattern utilizing 4 injectors and one central producer. Five sampling wells and four observation wells will be drilled to monitor the flood performance in both the A1 and A2 sands. The evaluation of flood results have been based on actual log and core data collected before, during and after surfactant injection. A reservoir simulation model will be used to history match production performance and to scale up the process for field wide performance predictions. The selected finite difference simulation package is equipped with surfactant and polymer options.

This paper will discuss both reservoir and facility aspects of the Surfactant Field Trial design and implementation. In the future, actual recovery efficiency of both surfactant systems will be reported and compared to performance predicted from laboratory test results & reservoir modeling.

Historically surfactant floods have not been viewed favorably due to their high cost & moderate recovery1. However, the low cost of production of Lignin II and Synthetic Petroleum Sulfonate may change the way we view surfactant flooding if their high recovery is proven in the field trial.
W.F. James No. 1 (Hunton-Arbuckle) Mills Ranch Field, Wheeler County, Texas
Authors: Leonard J.W.
Published: December 2007

The Mills Ranch (Hunton) Field was discovered in 1972, and a total of seven Hunton producers were drilled prior to spudding the producers were drilled prior to spudding the James No. 1 on 2-14-75. The James was drilled to 21,670' as a Hunton development well and deepened on 24,482' as an Arbuckle exploratory hole. The well reached total depth in December, 1975; 318 days after spudding. Drilling operations were reasonably trouble free except for a voluntary sidetrack that occurred at 22,308' while on a trip for a new bit at 24,092'. The well was completed as a dual gas producer with the Hunton potentialing for producer with the Hunton potentialing for 72,000 MCFD from perforations 20,747'-21,330' and the Arbuckle potentialing for 31,000 MCFD from perforations 22,918'-23,937'. Although at least one other well has produced from a greater depth, the James is believed to be the world's deepest commercial gas well. Drilling problems encountered in drilling later Arbuckle problems encountered in drilling later Arbuckle wells in the field are also discussed.

Introduction

The Mills Ranch Field is located in southeastern Wheeler County, Texas, in the Texas Panhandle and approximately five miles west of Panhandle and approximately five miles west of the Oklahoma state line (Fig. 1 and 2). Chevron U.S.A. Inc. is operator for the field and owns approximately 38% of the Hunton production and 43% of the Arbuckle production.

The field lies to the north and adjacent to the buried Amarillo Mountains but separated by large normal down-to-the basin (Anadarko) faults, which preserved the Pre Pennsylvanian sediments. Pennsylvanian sediments covered the down-faulted blocks with conglomerates, sands and granite washes as a result of erosion of the Amarillo Mountains. Wolfcamp sediments overlie the Pennsylvanian formations (Fig. 3). Overthrusting of the Pre Penn sediments in early Pennsylvanian time formed fault blocks which Pennsylvanian time formed fault blocks which were later buried by sediments. Accumulation of hydrocarbons migrating from the Anadarko Basin were trapped in the updip fault blocks. The Mills Ranch Field is an asymetrical northwest-southeast aligned structure, with the primary pay zones being the carbonate Hunton and Arbuckle formations.

The Mills Ranch (Hunton) Field was discovered in 1972, and a total of seven Hunton producers were drilled prior to the James No. 1 producers were drilled prior to the James No. 1 well. The Hunton producers are completed with a total depth of approximately 21,500'.
Novel Stimulation Technique Proven Effective in the World's Biggest Deep Gas Producer
Authors: Crenshaw P.L. , Joines B.R.
Published: December 2007

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

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

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

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

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

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

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

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

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

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.
Practical Uses Of Pressure Build-Up Analysis In The Anadarko Basin Completion And Repair Operations
Authors: Smith Kim L. , Feemster W.E.
Published: December 2007

The Horner and Miller-Dyes-Hutchinson methods of pressure buildup analysis have long been the basis of such analysis. Advances in analysis theory have added to and combined these two methods to provide engineers with a thorough understanding of a reservoir. This article compiles a practical method of pressure buildup analysis for the Morrow formation in the Anadarko Basin of Central Oklahoma based on experience gained from repeated analysis of pressure data in this region. The article reviews the familiar equations for permeability and skin effect, and discusses the three plots required for proper analysis with a detailed look at afterflow, fracturing, identification of the correct straight lines on each plot, and average reservoir pressure. Buildup analyses for both pre-frac and post-frac pressure data are presented for a gas well and an oil well. The analysis pressure data are presented for a gas well and an oil well. The analysis is discussed with emphasis placed on the value of such testing in completion and workover operations.

THEORY

All pressure analysis is based on the two-dimensional diffusivity equation in cylindrical coordinates written:

(1)

The diffusivity equation is assumed to describe the flow within the reservoir and the equation itself assumes constant porosity, fluid viscosity, compressibility coefficients, and formation dimensions, as well as single-phase, isothermal, radial flow toward the wellbore, a slightly compressible flowing fluid, isotropic permeability, and no gravity effects.

Horner presented a solution of this equation which resulted in the basic practical equation used in all pressure analysis. practical equation used in all pressure analysis.
Water-Base Spacer Increases Success Ratio Of Cement Jobs In Illinois Basin
Authors: Griffin T.J. , Crowe W.L.
Published: December 2007

The application of a water-base spacer ahead of cement during oil or gas well cementing operations improves cementing results. Better bond logs are achieved, better zone isolation is accomplished and stimulation treatments are more effectively applied. With more effective stimulation treatments, production results are improved. Bond logs production results are improved. Bond logs and field results including production data are presented.

Introduction

Wells in the Illinois Basin drilled through the St. Genevieve limestone and all formations through the Trenton formation have had production which was far below the expectations of formation log and drill-stem tests. These fractured limestone formations occur between 2000 and 4000 feet and are drilled with a simple, light-weight, waterbase drilling mud. The poor production is attributed to a lack of zone isolation by the cementing treatment. Poor zone isolation occurs when mud is left in the annulus and forms a channel behind the cement.

ELEMENTS OF GOOD CEMENT JOB

To ensure a good cement job, the best cementing techniques must be employed. Of course the first element of a good cement job is the cement itself. The cement system must be properly designed for the well conditions If well conditions permit, casing hardware such as centralizers and scratchers should be employed, especially across any zones of interest or future zones of interest. After the casing or liner, has been run into the hole, mud should be circulated at least "bottoms up", or until it is in good shape. Following mud conditioning, cement must be mixed and placed using proper techniques. For cement to make intimate contact with the formation and pipe, which is necessary to achieve good bonding and good zone isolation, all the mud must be displaced by the cement. Pipe movement, such as rotation or reciprocation Pipe movement, such as rotation or reciprocation during placement of cement will greatly aid mud removal. Spacers are also available which will improve mud removal and its replacement by cement.

REMOVAL OF MUD

Removal of mud may be a very difficult task, even with proper mud conditioning, pipe movement, and use of casing hardware. Most muds are incompatible with cement, whether they are high density muds or simple, lightweight muds.
A Search For Energy From The Antrim
Authors: Matthews R. David , Humphrey John P.
Published: December 2007

The Dow Chemical Company's interest in oil shale was directed in the 1950's toward in situ processes and local shales, specifically the Antrim, a black Devonian shale which occasionally produces natural gas and which yields produces natural gas and which yields 9–10 gallons of oil per ton when retorted. It underlies most of the lower peninsula of Michigan.

Various field studies by Dow of the Antrim shale have resulted in the drilling of some 21 wells and the cutting of over 5000 feet of core. Dow researchers have retorted Antrim shale in laboratories and in surface retorts and underground combustion experiments have been conducted in a quarry and through bore holes at depths of 1200' and 2600' below the surface. Both high pressure air and oxygen have been used underground as reactants. Hydraulic fracturing and chemical explosives have been used on a massive scale in attempts to generate the necessary fracture permeability for in situ retorting. The costs have been large and the technological problems yet to be solved are formidable, however the potential of the eastern oil shale is so large that a continuing effort has been recommended to the Federal Government.

Introduction

As early as June, 1955, research planners for The Dow Chemical Company were suggesting that underground processes, including in situ retorting, be studied with specific attention to the essential problem of rubblizing the strata, because the long range availability of energy and organic raw materials was not favorable at some Dow plant sites. A block of Colorado oil plant sites. A block of Colorado oil shale was purchased, however, interest soon shifted to a local oil shale a little more than half a mile below our power plants at Midland, Michigan. This shale, plants at Midland, Michigan. This shale, the Antrim of Michigan, is a Chattanooga-type shale that represents only a small part of the very extensive oil shale deposits of Devonian age in the Eastern and Mid-eastern parts of the United States (Figure 1). parts of the United States (Figure 1). The U.S. Geological Survey estimates that these shales underlie an area of over 400,000 square miles.
Ecotoxicology of Oilfield Chemicals: The Relevance of Evaluating Low-dose and Long-term Impact on Fish and Invertebrates in Marine Recipients
Authors: Beyer Jonny , Skadsheim Arnfinn , Kelland Malcolm A. , Alfsnes Kjetil , Sanni Steinar
Published: December 2007

Should future regulation of the use and release of E&P chemicals offshore focus more on tests of chronic effects at low levels of contamination, in line with recent ecotoxicological discoveries? Within this context, what groups of E&P chemicals are relevant, and what kind of effects and test methods should be incorporated in revised regulations? Can this altered but more relevant environmental focus potentially be beneficial for both the environment and the oil E&P sector? This presentation will discuss and answer these issues.