bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Method for Evaluating Layer Productivity Using a Permanent Monitoring System
Authors: Da Prat G. , Eliseche L. , Iriarte J.
Published: December 2007

A new method is presented for layer evaluation in pumping wells based on the inflow-performance relationship (IPR) determination for each layer contributing to the well production. Both the theory and field examples of the application are explained. The fundamental principle of the method is the IPR determination for each layer that is contributing to the well production. A permanent monitoring system consisting of a permanent gauge and a shut-in valve is installed in the well to discriminate the flow rate from each layer corresponding to a given stabilized formation dynamic pressure. The method is inherently quality controlled: both rate and transient pressure are continuously monitored at the surface during the test to assure stabilized conditions for a valid IPR.

The new method is illustrated with field cases of wells located in the Chihuido de la Sierra Negra oil field, Argentina, which is undergoing a secondary recovery project by water injection. Water is injected and produced from two main layers. Both lateral and vertical displacement efficiency determination have been evaluated from the beginning of the project. In most of the wells, production from the two main zones is combined. A permanent monitoring system was installed in several key wells, and the IPR for each zone was obtained. The rate from each layer was obtained directly using the system. In addition, the reservoir pressure was obtained by direct measurement and an interference test conducted using one of the nearby injectors as the active well.

A relevant conclusion obtained in one of the evaluated wells was that the production of one of the layers was responsible for most of the total production, contrary to the expected results based on conventional methods of assigning layer production based on total production split according to layer petrophysical properties. IPR data fit was done using the Fetckovitch model.

It can be concluded that the methodology presented can be considered as a major breakthrough in testing and evaluation of layer productivity applicable to multilayer completions.
The Integration of Geology and Well Testing for Improved Fluvial Reservoir Characterisation
Authors: Corbett Patrick , Zheng Shi-Yi , Pinisetti Moe , Mesmari Abdallah , Stewart George
Published: December 2007

Fluvial reservoirs are important hydrocarbon reservoirs worldwide. It is the fluvial depositional characteristics that give rise to the complex reservoir architectures/geometries, spatial distributions/patterns, internal heterogeneities/petrophysical properties as well as the connectivity between flow units/channel sands that combine to give great uncertainty in characterising the effective reservoir properties.

Well testing, which measures the dynamic response of the reservoir, is potentially a very important tool for investigating these properties in fluvial reservoir systems. Through the integration of geoscience and engineering, the uncertainty resulting from reservoir description and well test analysis in such heterogeneous systems can be substantially reduced.

This paper reviews the latest techniques developed from the integration of geology and well testing for fluvial reservoir characterisation. Starting from the classification of fluvial systems, deterministic geological models, based on the two end members of fluvial systems (Meandering and Braided), have been mapped out.

A well test interpretation model for meandering channel reservoirs, the Pseudo-channel model has been distilled, which removes the assumption of the uniform formation thickness. Numerical solutions, termed Geotype curves have been derived. A new measure for the reservoir heterogeneity leading to an Effective flow interval has been developed, which shows a significant improvement from the conventional core analysis method. Geoskin as a geological phenomena has been identified and the technique quantifying its value with respect to geology has been developed. A wealth of geological data sets, derived from ancient (outcrops) and modern rivers, have been integrated. Fluvial Flow System Diagnostic Plots (FFSDP) have been developed, with which ten well tests of Tertiary channel sand reservoirs from the Gulf of Thailand have been evaluated.

Based on these studies, a Two-stage diagnostic procedure for well test analysis has been developed. A confident interpretation requires that the tested system should be clearly mapped out prior to the transient data analysis in ensuring the correct selection of the interpretation model. Then the meaningful reservoir parameters can be inverted. The final match to the tested data should be made by the Numerical solution from the defined reservoir system, rather than "force" an analytical model, which are mostly idealised, for the match.

An improved understanding on the scale and limits of the disciplines involved in reservoir characterisation is crucial for the integrated studies. This study gives insights into the integration and scaling of measurements as well as the need for improved geological, petrophysical and dynamic descriptions.
Composite Drill Pipe for Oil and Gas E&P Operations
Authors: Lou Alex Y. , Souder Wallace W.
Published: December 2007

Composite high torsional stiffness, strength and light weight properties are particularly applicable in extended reach drilling. Composite drill pipes can be designed to provide improved resistance to buckling and a reduction of friction and drag while saving 50% of the weight. The horizontal distance can be easily increased 40% from 25,000 to 35,000 feet over the conventional steel drill pipe. In offshore E&P operations, more oil and gas reserves can be reached from a single drill platform. Thus, substantial saving can be realized from fewer, smaller and lighter structures. This is extremely important in deepwater operations, where the platform weight is a major design consideration, additionally, this extended reach capability allows many reservoirs to be tapped from existing structures, which probably will not be developed otherwise. Additionally, real time monitoring of logging while drilling (LWD) and measurement while drilling (MWD) is limited by the rate of transmission of signals to the surface. Current technology utilizing pressure pulses in the mud stream is limited to about 10 pulses per second. Replacing the electrically conductive drill string with one having low conductance, such as a composite drill pipe, would permit deployment of electromagnetic transmission systems and could potentially increase the transmission rate by several orders of magnitude.
Managing the Platform Decommissioning Process
Authors: Griffin William S.
Published: December 2007

Until the summer of 1995 the decommissioning of redundant offshore oil and gas facilities was thought to be just another construction project. Public pressure and the resulting political turmoil from the Brent Spar incident showed there are more factors to be considered than technology and the applicable regulatory regime. The UK authorities did everything required by the regulatory regime and the operator applied good science and technology in arriving at the recommended disposal option, yet the Brent Spar remains today in a Norwegian Fjord.

To discuss "Managing the Platform Decommissioning Process", it is important to review the lessons learned and to consider factors related to decommissioning highlighted by industry's recent experiences.
Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects
Authors: Turta Alex T. , Singhal Ashok K.
Published: December 2007

An in-depth analysis was conducted for over forty foam applications in Enhanced Oil Recovery (EOR) projects, and numerous production well treatment operations involving the use of foam in cyclic steam operations and in gas miscible floods, to derive insights on screening and design aspects in such applications. Foam can be used to solve conformance problems caused by either a thief zone or gravity override; The proper identification of the cause, as well as of the production well(s) affected is basic to the definition of the problem. Either blocking/diverting foams or in-depth mobility control foams can be placed through the injection wells. On the other hand, foam treatment in production wells is done mainly to mitigate an override problem. The most important factors in foam assisted EOR projects were determined to be: (a) manner of foam placement in the reservoir (injection of pre-formed foam, co-injection foam and SAG or surfactant alternating gas foam), (b) reservoir pressure and c) permeability. While pre-formed foam are effective mainly in the treatment of the production wells, the co-injection foam and SAG can be employed for solving specific sweep efficiency problems in EOR projects. It is concluded that for designing a steam-foam project (which is essentially a low pressure foam application) a foam quality in the range 45% to 80% should be considered. In this kind of application, a co-injection foam is to be employed and the additives (surfactant and non-condensable gas) are to be injected intermittently (on and off), superimposed on a continuous steam injection. Injection cycles as short as 7 days (2 days-on and 5 days-off) should be considered. Under suitable conditions, an oil rate increase of 1.5 to 5 times, a decrease in water cut by 20 %, and an incremental oil recovery of 6%-12% OOIP can be achieved with such an implementation. At high pressure, such as in gas miscible flooding (CO2 and hydrocarbon gas), foam application can result in excessive mobility reduction factors, and injectivity reduction. Due to this reason, alternate injection of surfactant solution and gas (SAG foam) is favoured over a co-injection mode of placement. Recommendations for laboratory tests in support of a proper design of the field pilot are presented.
A New Two-Dimensional Model for Acid Fracturing Design
Authors: Settari A. , Sullivan R.B. , Hansen C.E.
Published: December 2007

The paper describes a 2-D model of acid fracturing which is more rigorous than current acid fracturing simulators. The equations are discretized and solved along fracture length and across the width (in × and y directions), as opposed to a lumped formulation in the conventional model in which the y-solution is replaced by a mass transfer coefficient Kg. In the 2-D model, correlations for Kg are not needed, and the model uses only directly measurable data. In addition, the model can represent transient effects (Kg variable along frac length and in time) combined with dispersion and thermal effects.

Two models, one for lab experiments and one for field design, were developed. The lab model was validated against results of Roberts and Guin with excellent agreement and compared with the l-D approach on data typical for Phosphoria dolomite. The results show large differences in regions of high as well as low leak-off. Also, acid spending predicted by the 2-D model is higher even when the Kg values are comparable. Correspondingly, the field design model predicts larger spending and frac conductivity.

An example of the field design and post frac history match from the Cottonwood Creek Unit, Washakie County, WY is presented. It shows that the new model is in better agreement with field data. Extensions to a 3-D modeling are also discussed.

P. 39
Modeling a Jet Pump with an Electrical Submersible Pump for Production of Gassy Petroleum Wells
Authors: Carvalho P.M. , Podio A.L. , Sepehrnoori K.
Published: December 2007

The objective of this work is to present the concept of the Electrical Submersible Jet Pump (ESJP). It is a new artificial-lift method for application in the petroleum production industry This proposed artificial-lift method uses an electrical submersible multistage centrifugal pump in combination with a jet pump installed in the well bore along the tubing string. Such a method is proposed to allow production of high gas- liquid-ratio petroleum wells using the existing electrical submersible pump technology. While applicable to any petroleum well, the driving force and main motivation for the development of this new technology is deep offshore petroleum production. In this work, also presented is a numerical model developed to simulate the operation of the system. In such a model, the system is analyzed as three coupled subsystems: the electrical submersible pump (ESP), the low gas-liquid-ratio (GLR) multiphase flow in the tubing string, and finally the flow inside the jet pump (JP). Both individual models used for the ESP performance and the multiphase flow inside the tubing string are available in the literature. In this paper we present the modeling of the multiphase flow of fluids inside the liquid-jet gas pump (LJGP), which was developed based on the simultaneous solution of the mass, momentum, and energy conservation equations.

P. 53
Gradual Deformation of Continuous Geostatistical Models for History Matching
Authors: Roggero F. , Hu L.Y.
Published: December 2007

This paper presents a new methodology for constraining 3-D stochastic reservoir models to well and historical production data. Based on the inversion framework, this methodology is mainly composed of a new algorithm for gradually deforming continuous geostatistical models and of an efficient optimization algorithm. The gradual deformation algorithm generates a process of realizations which evolve smoothly while preserving the overall statistical characteristics of the stochastic model. Deformation control by a limited number of parameters improves the efficiency of the process. In comparison with other approaches, the number of iterations is significantly reduced.

The deformation procedure can be coupled with an optimization algorithm to obtain automatic history matching capability. The inversion of several model parameters and the gradual selection of a new constrained realization can be performed simultaneously. The analytical gradient method as well as approximated gradients are used to improve the convergence rate of the procedure.

The successful application to a 3-D synthetic case, derived from an actual field case, is described in the paper. The shape of the top structure of the reservoir and the activity coefficient of an aquifer are simultaneously constrained to the historical data recorded for 5 wells. The structural uncertainties are described by a geostatistical model. The definition of the top structure is improved by gradual deformation to ensure the geostatistical consistency of the model during the match of production data. An interference well test case is also presented to illustrate the decrease in uncertainties obtained by integrating a geological description and pressure data.

P. 221
Taking Low Gels to New Highs
Authors: Herring Randy B. , Diede Loren L.
Published: December 2007

This paper documents the evolution of a 2 year hydraulic fracturing program in the Conoco operated San Juan 28-7 Unit located in the San Juan Basin of northwestern New Mexico. This fracturing program utilizes a crosslinked 15 lb. Gel system to pump stimulation treatments at bottom hole temperatures up to 1800 F. Historically, slick water treatments and linear gels have been used to hydraulically fracture the Dakota sandstone in this area. These low viscosity fluids are utilized in an attempt to limit fracture growth into the underlying water bearing zones. Crosslinked gels and nitrogen foam fracs have also been used by some operators in the immediate area on a limited basis. Large, relatively expensive fracs are rare due to economic constraints based on the average well's modest production rate.

These low viscosity fluids require large volumes of water at high rates with low proppant concentrations. Problems associated with these low viscosity treatments include premature screenouts and limited availability of large quantities of, relatively expensive, quality water. The design of the cross-linked low gel load fluid grew out of a need for an economical treatment that could adequately prop the low pressure, low permeability Dakota Sandstone while minimizing gel damage.

To date, 65 frac treatments have been successfully completed using the crosslinked 15 lb gelled fluid. Success in this instance is measured by placing 100% or greater of the designed job at or below projected costs. The success of the Dakota program led to the use of this treatment in the shallower Mesaverde formation.

In the past two years, completion and recompletion costs in the Mesaverde and Dakota formations have been reduced 12% through decreased water volumes and reduced post frac clean up time requirements. In addition early production results indicate that wells treated with this crosslinked low gel system exceed or are comparable to wells treated with other, higher cost treatments.

P. 267
Results of Using a Relative-Permeability Modifier with a Fracture-Stimulation Treatment
Authors: Dalrymple E.D. , Creel P. , Rohwer C. , Crabb H.
Published: December 2007

When stimulation treatments are performed on oil- or gas- producing zones with high-permeability streaks that produce water or that feature water influx, these water-producing zones are often unintentionally stimulated along with the productive zones. In such instances, water production from the formation may be excessive, requiring expensive separation and water disposal. After a stimulation treatment has been performed, a water-control operation may be performed to reduce water production, but the remedial treatments are expensive and are not always successful. Furthermore, the process can result in a plugged formation and lost production.

This paper discusses field results from the combination of a relative-permeability modification (RPM) agent with a fracture- stimulation treatment. The design objective was for the modification agent to be leaked off into portions of the created fracture during the stimulation treatment, thereby alleviating water- production problems. The treatments were performed in April 1997 in the Brushy Canyon formation in southeast New Mexico, a Delaware sand reservoir. Previous fracture treatments in this interval had resulted in water cuts greater than 60%, and the continued production of these wells had been deemed uneconomical because of the presence of damaging scale and a subsequent decline in total fluid production. (The water cuts would remain at 60 to 70%, but the total volume of fluid would decline.)

As a result of the combination of the relative-permeability modifier with the fracture-stimulation treatment, the wells averaged a 65% increase in oil production, a 122% rise in gas production, and a 60% decline in water flow compared to wells stimulated without the RPM agent.

P. 285
Completion and Stimulation Practices in the Prolific Cotton Valley Reef Trend of East Texas
Authors: Richardson Michael F.
Published: December 2007

Over the last several years there has been a highly competitive and active exploration effort focused on the discovery of gas reserves from the Upper Jurassic Cotton Valley Lime (Haynesville) interval in the East Texas Basin. The primary exploration objectives along this carbonate platform are overpressured sour gas Cotton Valley reefs. The frantic land, 3D seismic, and drilling activity have been fueled by some outstanding early results. Initial results drove expectations for the play to unrealistically high levels that included average per well reserves of 70+ Bcf, initial potentials above 25 MMcf/d, and a chance of success using 3D seismic of better than 65% 1-4. As the play has matured and industry's knowledge has increased, these lofty expectations have significantly fallen, but overall trend statistics remain attractive. Recently, in an effort to improve the economics of the play, large hydraulic fracture treatments have been routinely incorporated in the completion of these wells. However, the stimulations have been largely unsuccessful for several reasons. These include high treatment costs, high fracture gradients, the lack of a primary horizontal stress direction, a highly heterogeneous reservoir, poor barriers to fracture height growth, and poor initial estimates of key reservoir parameters. Proper reservoir characterization, depletion of reservoir pressure prior to stimulation, and application of horizontal drilling are offered as possible completion alternatives.
Integration of Discrete Feature Network Methods with Conventional Simulator Approaches
Authors: Dershowitz Bill , LaPointe Paul , Eiben Thorsten , Wei Lingli
Published: December 2007

The discrete feature network (DFN) approach offers many key advantages over conventional dual porosity (DP) approaches, particularly when issues of connectivity dominate recovery and reservoir stimulation in fractured and heterogeneous reservoirs. DP models have been developed for complex multiphase and thermal effects, and have been implemented for basin scale modeling. However, DP models address only the dual porosity nature of fractured reservoirs, generally simplifying connectivity and scale-dependent heterogeneity issues which are modeled efficiently and more accurately by the DFN approach.

This paper describes the development of techniques to integrate DFN and DP approaches. These techniques allow the analyst to maintain many of the advantages of the DP simulator approach without losing the realism of complex fracture system geometry and connectivity, as captured by DFN models.

The techniques described are currently used within a DOE funded research project for linking a DFN and a DP thermal simulation model for the Yates Field, Texas. The paper describes some of the geological and engineering aspects of the Yates Field and gives two examples how DP parameters for the thermal simulation can be derived using DFN modeling techniques.

P. 351
Core Analysis for Optimum Reservoir Exploitation
Authors: Hensel W.N.
Published: December 2007

INTRODUCTION

Core data can play a vital role in development drilling programs and recovery planning operations. Well-conceived field coring programs and subsequent laboratory testing procedures can strengthen log interpretation criteria, aid in completion/stimulation operations, provide a sound basis for reserves estimates and reservoir modeling, and supply much needed guidance in secondary and tertiary recovery programs.

This paper presents the need for preplanning during the development phase of the reservoir so that necessary parameters are properly evaluated. Coring methods, coring fluids, preservation techniques, and basic laboratory testing procedures are discussed. Suggestions are given for selecting samples for special analysis test work.

THE FIELD CORING PROGRAM

The special core study actually begins during the development drilling program of the field. Failure on the part of all concerned to recognize this can severely encumber the proper planning of pressure maintenance, and secondary and tertiary recovery programs. After all of the wells have been drilled, it is too late to recognize the need for representative cores. A handful of sophisticated suites of logs are poor consolation to the reservoir engineer charged with designing the most efficient means for the recovery of millions of barrels of oil.

The development drilling program gets a lot of attention in its early stages. Drilling problems are encountered and ways are sought to lower the per-footage costs. Coring can only increase such costs. Logs provide a quick, clean way to identify producing intervals. Cores, although helpful, have a longer turnaround time and may cause delays in assigning perforations. The impetus for coring must come from those responsible for the long-range look at the reservoir. A logical choice is the reservoir engineering staff. Through their guidance, an orderly plan for coring operations may be followed, thus insuring that proper data will be available for future studies.

So, how may effective plans be made for the coring program to maximize the return on the data dollar invested? Some companies reportedly use rules of thumb based on the estimated oil in place. Certainly the worth of the reservoir should be a part of the consideration, but it is also important to look ahead and plan the coring to provide guidance in certain areas. What are these areas and how can cores and core data contribute?
The Energy Market Today - An Economic Appraisal
Authors: Perry Harry
Published: December 2007

This paper was prepared for the 1974 Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Washington, D.C., Nov. 14–15, 1974. Permission to copy is restricted to an abstract of not more that 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publications elsewhere after publication in the paper is presented. Publications elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually grated upon request 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.

In the past two years, the energy economy of the U.S. and the rest of the world has been jolted by a series of events that have altered appreciably the historic nature of the energy market. The factors that have caused these major changes in energy markets and the prospects for their continuation in the future are examined. Future prices for energy and the sources of supply are discussed as are the prospects for reduced demand through price prospects for reduced demand through price elasticity, changes in lifestyle, increased conversion efficiencies and energy conservation.

The projections of future energy developments are made for two time frames—the next 10 years and the period beyond. This distinction is necessary because of the long lead times required to make significant changes in either supply or demand without direct government involvement or controls.

The nature of the many different areas in which federal involvement can affect the future of the energy industries and the various federal options and their different impacts are analyzed.

Introduction

In relatively few years nearly everything about the energy industries has changed so rapidly that the historic problems with which we wrestled in the past now no longer seem real. The great debates over whether coal prices would increase from 20 to 25 cents per million Btu or whether the regulated wellhead price of natural gas should be 18 or 20 cents per million Btu are as a dream that never really was. This sudden change in the energy situation was not entirely unanticipated, although some important events which occurred suddenly and without any warning greatly accelerated and aggravated a developing problem. As a result, the two hundred years of low-cost adequate supplies of domestic energy resources available in any form desired came to an abrupt end with the beginning of the decade of the 70s.

To understand what has happened and where we are today requires a separate review of each of the energy industries since no two of them have been influenced by exactly the same factors.
Economic Impact of LNG on Natural Gas Supplies Distribution
Authors: Pastuhov Alexis
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the 1974 Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Washington, D.C., Nov. 14–15, 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 paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted upon request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the SPE magazines.

The annual estimated curtailment of firm requirements for natural gas for 1974–1975 is 1.8 Tcf. Even if all pending LNG projects were approved today pending LNG projects were approved today they would bring in only 1.2 to 1.45 Tcf. The economic impact of new LNG imports are expected to be important as the exporting countries value their resources on its BTU content and will index natural gas to crude oil. A typical transmission company importing LNG may see its average selling price increase by a factor of 1.6 or more.

Introduction

Has the pendulum swung the other way? This may be the situation today in the LNG business; only two years ago at LNG 3, Washington, D.C., a euphoria prevailed about the bright future of LNG imports to the United States. Today, however, the U.S.A. is at the crossroads of whether or not large scale imports of LNG will materialize. Several major LNG contracts are in the process of being renegotiated. They are El Paso II, Easco, Panhandle Eastern Trunkline, Distrigas (Ben Franklin) and Pacific Lighting (Indonesia). These contracts were scheduled to deliver LNG as early as the spring of 1975.

Background

This paper will deal exclusively with the import of LNG to the United States from an overall point of view and will not examine in detail the effect of the numerous peakload shaving plants now existing or being constructed in the U.S.A. processing pipeline gas and storing LNG in one or more large scale storage tanks.

In the opinion of the author, as long as pipeline gas will remain relatively inexpensive pipeline gas will remain relatively inexpensive in comparison to imported LNG, the public utilities as well as the transmission lines will continue to develop peakload shaving plant and storage facilities as a way of satisfying their winter load requirements. It is obvious that the effect of these facilities is to level the pipeline sendout between summer and winter time.
A New Approach to Preventing Lost Returns
Authors: Carlton L.A. , Chenevert Martin E.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Lost returns are one of the oldest problems associated with rotary drilling. problems associated with rotary drilling. Millions of dollars are spent each year by the industry for mud materials and lost rig time because of this problem.

A new technique for preventing lost returns during normal drilling operations has been developed. The technique combines the use of a standpipe choke to minimize pressure required to "break circulation"; pressure required to "break circulation"; the use of a Pressure Integrity Test to determine formation fracture pressure; and a method of accurately calculating and monitoring annular pressure losses while circulating.

Data from a field test where annulus pressure losses were measured with downhole pressure losses were measured with downhole pressure gauges are presented. Predicted pressure gauges are presented. Predicted annular pressure losses, calculated from different mud property measurements are compared to the actual measured losses. Annular pressure losses car, be accurately predicted by calculating inside drill predicted by calculating inside drill string losses and subtracting these from total circulating pressure. The calculation procedure for determining annulus pressure losses is simple and can be made by personnel at the rig using actual field data.

Introduction

Most lost returns occur while circulating or attempting to break circulation. Lost returns may also occur because of high surge pressure created while running pipe and because of vuggy or fractured formations. Except for the case of vuggy or naturally fractured formations, when returns are lost, there is only one cause for the lost returns; THE PRESSURE IN WELL BORE EXCEEDS THE STRENGTH OF THE WELL BORE! On this basis it should be obvious that most lost returns can be prevented if:The strength of the wellbore is known andthe pressure imposed on the wellbore is controlled at a level below that required to fracture or break down the formation.

Several techniques have been developed recently which have proved to be very helpful in reducing the occurrence of lost returns. The stand pipe choke, the pressure integrity test and a new pressure integrity test and a new technique for determining annulus pressure losses and controlling these pressures at a level below fracture pressure will be discussed.
Future Natural Gas Supply Reactions to Higher Prices - Projections of the A.G.A. TERA Model
Authors: Hardy Edwin F. , Neill Charles P.
Published: December 2007

Future Natural Gas Supply Reactions to Higher Prices - Projections of the Prices - Projections of the A.G.A. TERA Model

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The paper describes the total energy resource analysis (TERA) model developed by the American Gas Association. Emphasis is given to the submodel on natural gas supply. U.S. gas supply projections developed by TERA, using three quite different gas pricing policy scenarios, are reviewed for the time period 1975 to 1985.

Study results indicate that significant gas supply increases during the period 1980 to 1985 will require substantial near-term producer price increases and other policies favorable to price increases and other policies favorable to domestic energy development.

Introduction

In the spring of 1971, when the U.S. natural gas supply shortage was becoming increasingly apparent as the number one problem facing gas transmission and distribution utility companies, the American Gas Association (AGA) initiated design of the "total energy resource analysis model," or TERA model. As now developed, TERA is a computerized simulation model of energy supply, demand, and prices, with special emphasis on the gas industry. TERA incorporates data on all fuels and electric energy in different market sectors for each census region of the U.S., including factors that influence the energy industries-demographic, economic, technological, environmental, regulatory, legislative, and competitive.

TERA has been developed to assist the AGA staff and member companies in developing long range planning studies, policy positions on issues facing the gas industry, and responses to the many questions being asked about the future of this industry. TERA is helping to answer such questions as the following.What producer prices for natural gas will be required to reverse the 6-year reserves decline being experienced now, and when could this reversal occur?How much will natural gas demand be reduced as producer prices increase?What impact will supplemental gas supplies have on total supplies, demands, and consumer prices for gas?What effect will environmental regulations have on gas prices, demands, and supply schedules?What effect will various pricing and supply scenarios for competitive fuels have on the supply and demand for natural gas?

TERA is now answering these types of questions and showing how the answers vary under the influence of changing input variables.
Trends And Projections In Soviet Energy Output
Authors: Shimkin Demitri B.
Published: December 2007

1961 SPE Annual Meeting, Dallas, October 8–11, 1961

Over the past four years, much authentic information on energy resources, technology, output and utilization in the Soviet Union has become available. The major sources have been technical Journals such as Ugol' (Coal), Neftvanove khoz Vavstvo (Petroleum Economics), and Torfvanava promvshlennost' (Peat Industry); and monographs published by the State Fuel-Technology Press (Gosgortekhizdat), the State Mining-Technology Press (Gosplanizdat), the State Electric-Power Press (Gosenergoizdat), the Coal-Technology Press (Ugletekhizdat), the State Planning Press (Gosplanizdat), and the Academies of Science of the Soviet Union and its Republics. Statistical handbooks published by the Central Statistical Administration, the Ministry or Foreign Trade and other official bodies have also proved valuable. In general, these materials are far more reliable and comprehensive than popular sources or casual Western observers. While ambiguities, gaps and errors do occur, and while differences from Western concepts and practices impose caution, the Soviet technical sources are largely competent, explicit and consistent. Properly used, the data are adequate to develop an effective understanding of Soviet techniques and accomplishments, problems and plans, in energy development and use (see also Shimkin, 1960; n.d.-a.; n.d.-b.)

In this discussion, I shall try to sketch the current energy-resource position of the Soviet Union; major trends and plans in energy output, by source and by region; and current and planned patterns of energy use. I shall also make selected comparisons with the United States, thereby highlighting distinctive features of Soviet practice. One I shall retain for consistency's sake.
Geosteering Horizontal Wells in a Thin Oil Column
Authors: Barry Andrew , Burnett Phil , Meakin Chris
Published: December 2007

A multi-disciplinary team utilising state-of-the-art Logging While Drilling (LWD) technology is able to geologically "steer" horizontal wells in real-time within a thin oil column. Excellent well performances support the general validity of the geosteering approach and a static pressure survey in one of the wells verifies the steering accuracy.

The Tuna field M-l reservoir in the Glippsland Basin, Bass Strait, Australia contains a 12 m oil column overlain by a large gas cap and supported by a strong aquifer in multi-darcy sands. A total of 19 wells with horizontal sections of 300 to 1050 m in length are being drilled to develop the reserves, with all wells being steered using LWD data to maintain true vertical depth (TVD) control.

Reservoir simulation defines the optimal horizontal well placement as 4 m above the oil-water contact (OWC), within a TVD tolerance window of +1.5 m. Industry standard error models show that this tight geometric tolerance over the length of the wells is not possible using MWD survey data alone. Tying the MWD survey data to the known gas-oil contact (GOC) during the landing operation reduces the geometric error prior to drilling the horizontal section, while control of the geometric error during horizontal drilling is achieved using the real-time resistivity and neutron-density data.

Well log data show that the entire oil column is in transition, allowing an empirical algorithm to be developed relating the resistivity response to height above OWC for a range of rock qualities. For each well path, TVD is determined in real-time to verify the directional survey data and adjust the well trajectory when necessary.

Comprehensive pre-planning, discussion, documentation and management approval of the decision making process empowers the project team. The process steps of landing the horizontal section, well trajectory error limit management, early well total depth decision-making and external packer placement are discussed.

P. 221
Use of Pressure Monitoring to Improve Reservoir Management in an Offshore Recycled Gas Reservoir - Goodwyn Gas Condensate Field, NWS, Australia
Authors: Scott M. , Evans M.
Published: December 2007

Effective Reservoir Management of a large gas condensate recycling field requires early recognition of the degree of communication between injectors and producers, aquifer strength and management of the key reservoir uncertainties. The objective of this paper is to communicate the requirement, acquisition, justification, applications and value of pressure data to improve reservoir management of the Goodwyn field.

P. 251
Boolean Modelling of the Fluvial Mungaroo Formation, Gorgon Field, Northwest Shelf, Australia
Authors: Brenneman R.J. , Miller N.W.D. , Teakle R.P. , Seeburger D. , van Nispen D.J. , Harrison C.J.
Published: December 2007

The objective in building the Gorgon reservoir characterisation and simulation model was to create a 3D, object based model in a sequence stratigraphic framework integrating core, log, engineering, and seismic attribute data. The project team specified that software and work flow must incorporate marked point - boolean processes with or without seismic conditioning, recognise uncertainties in reservoir and model input parameters, generate multiple model realisations for a probabilistic range of gas in place, and output the model in reservoir simulation format. Reservoirs are in stacked sands of the Mungaroo Formation, with a total formation thickness of greater than 2000 m beneath the major Jurassic unconformity. The Mungaroo Formation was subdivided into 11 intervals on the basis of regional sequence boundaries and systems tracts. Relative lowstand intervals are sand prone, relative highstand intervals much less sand-prone. Facies present include fluvial channels (single channels and amalgamated stacked channels), crevasse splays, and "background" shale (coaly siltstone, coal, and minor carbonate). 3D seismic data were used both for structural modelling and a statistical correlation between seismic attributes and channel sand distribution. Wireline pressure data were used to refine our understanding of stratigraphic compartmentalisation and fluid distribution. The fluvial reservoir architecture model was built using marked point process and simulated annealing for each of the 11 stratigraphic intervals. A range of endpoint net/gross ratios was established based on well penetrations and seismic attributes. The model was scaled-up from a 715 layer geologic model to a 46 layer simulation model, with no areal scale-up. Whilst the scaled-up model honoured the 11 original intervals, the majority of the layers were located in regions identified as key flow units. The resulting simulation model was then used to generate production profiles for various development scenarios.

P. 305
Displacement of Oil by Water-Effect of Wettability, Rate, and Viscosity on Recovery
Authors: Moore T.F. , Slobod R.L.
Published: December 2007

The displacement of oil by water in typical porous media has been studied, using new equipment developed to handle flooding experiments on 1-in core plugs with a precision of about one pore per cent. Long core floods using cores up to 10 ft in length were used to supplement the short core studies. From the results of several thousand flooding experiments on a variety of porous media, we have found that the wettability is the single most important variable affecting the recovery history of a water flood. Cores are, therefore, usefully described as being (1) water-wet, (2) oil-wet, or of (3) intermediate wettability. This classification scheme has provided a sound basis for the interpretation of laboratory waterflooding data.

For water-wet cores it can be concluded:1-in core plugs show the same recovery history as long cores when flooded under the same conditions of rate, viscosity and wettability;recovery is practically independent of rate of flooding from reservoir rates up to 40 ft/day;at extremely high rates (over 100 ft/day) significant recovery increases were observed;displacement by imbibition alone displaces the same quantity of oil as water drives do with rates up to 40 ft/day;lowering the interfacial tension will reduce residual oil if the lowered value is maintained at the flood front.

An explanation for these conclusions based on the interplay of the viscous and capillary forces at the flood front (called "Viscap" concept) is presented, and from this we may conclude that laboratory floods of water-wet core plugs offer no particular scaling problems.

The intermediate wettability case is more complicated, and because of limitations in measuring the wettability of cores and the reservoir, this group needs more study.

The behavior of oil-wet cores is markedly different from the water-wet case. Generally, oil-wet cores show a considerable amount of oil production after water breakthrough even for a viscosity ratio of unity. Also, they exhibit a saturation gradient at the flood front (sometimes called an end effect). This end effect invalidates laboratory results unless the floods are scaled using a relationship involving length, viscosity, rate, interfacial tension and contact angle.

Introduction

The need for secondary recovery procedures to reduce the fraction of oil left in the reservoir is generally accepted by the oil industry. One of the most effective of these secondary recovery methods is water flooding.
Geological Considerations of the Weber Sand Reservoir, Rangely Field, Colorado
Authors: Larson Thomas C.
Published: December 2007

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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The heterogeneity of the Weber Sand Reservoir required that a geological evaluation be considered with reservoir engineering to enhance primary and secondary recovery. Stratigraphic: studies delineate a multilayered distribution of discrete sand bodies. Lenticularity, lithology, crossbeds, and fractures cause preferential drainage, prohibiting a favorable balance of production and injection wells in many sands. These geological parameters have been considered in analyzing parameters have been considered in analyzing reservoir performance with subsequent increased production. production.

GENERAL GEOLOGY AND RESERVOIR CHARACTERISTICS

Rangely Field is located in northwestern Colorado on the north plunge of the Douglas Creek Arch between the Piceance and Uinta Basins (Fig. 1). The principal production is from the Permo-Penn Weber formation. Accumulation is Permo-Penn Weber formation. Accumulation is localized on an anticline of Laramide age. The Weber formation interfingers across the structure into the arkosic Maroon formation to the south.

The stratigraphy and depositional history of the Weber is pertinent as it relates to the reservoir of the field. The section here consists of some 600 to 800 ft of interbedded sands, silts, and shales of the Weber formation with tongues of shale, silt, and arkose of the Maroon formation. In general, the Weber is a buff, clean, well-sorted, fine-grained sandstone with variable calcareous cementation. A littoral marine environment apparently predominated in this area during Weber time. This caused sand bodies of various depositional modes to form complex multilayered and laterally coalescing sand units. The texture indicates a reworked mature deposit. Separating or forming laterally equivalent facies to these sand units are gray and red shales, red silts, and coarse maroon arkoses generally considered deposited in a deltaic environment with a source attributed to the Uncompahgre Highlands to the south.

Depth to the top of the Weber in the field ranges from about 5,500 to 6,500 ft, and penetration varies from less than 100 to more than penetration varies from less than 100 to more than 700 ft, depending on structural position. Fig. 2 depicts the structure as mapped on top of the Weber formation. An initial gas cap of about 130 ft was present on the crest of the structure. An oil column of about 800 ft was encountered above the generally recognized oil-water contact of -1,150 ft.

Porosity, permeability, and saturations vary within the Weber and within the field. In general, porosity in the sand is estimated to average near 15 percent.