bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Field Optimization: Well Compression Selection Methodology
Authors: Irwin Robert J. , Villavicencio Hector R.
Published: December 2007

To facilitate field and wellsite optimization, Natural Gas producers have come to rely on the strategic placement of compressors to increase production. Mature fields, with depleting reservoirs and/or low wellhead pressures, are ideally suited for this cost-effective gas recovery solution. The decision process by which the production engineer quantifies the placement of a compressor is of significant relevance. There are several strategies available to the production engineer to identify wellsites best suited for optimization. Total Systems Analysis simulation software, Decision Tree Analysis and Real Time Selection Opportunities (RTSO) enable this process. This paper reviews these decision alternatives and the application of the RTSO Risk Matrix to select ideal well compression candidates.
Depletion Performance of Poorly Stimulated Layered Reservoirs Without Crossflow
Authors: McCoy T. F. , Reese D. E. , Johnson P. G.
Published: December 2007

Many layered no-crossflow gas reservoirs when initially completed did not benefit from the use of selective stimulation. Without aid of an effective diversion technique, the stimulation treatment only acts on the high permeability layers. This generally leaves the lower permeability layers in a poorly stimulated condition. Significant upside potential may exist in mature areas through restimulation of the lower permeability intervals.

We present the results of a study of the depletion performance of a two-layer gas reservoir suffering from a poor initial stimulation. We assume that only the higher permeability interval has been successfully stimulated. A 2-D radial simulator is used to investigate the subsequent depletion performance after the low permeability layer is restimulated. Using a graphical presentation of rate versus time and pressure-cumulative production, we illustrate the restimulation effects on the depletion performance of these reservoirs. The graphical presentations clearly illustrate the advantages of re-stimulation as a function of volume ratio, layer skin, and abandonment rate. In addition, a 3-D Cartesian model is used to investigate the restimulation impact in competitive reservoirs. We discuss the magnitude of potential reserve increases and present several field case histories illustrating the restimulation effect. Guidelines for selecting potential restimulation candidates are presented.
Production Performance Evaluation of Hydraulically Fractured Wells
Authors: Poe Bobby D.
Published: December 2007

A detailed analysis procedure for obtaining estimates of the reservoir effective permeability, fracture effective half-length, and average fracture conductivity using the bilinear to formation linear transition regime duration production performance data is presented in this paper. A combination of fractured well diagnostic analyses and history-matching with analytic solutions are used to obtain reliable estimates of the average fracture properties and reservoir effective permeability. The transient performance models reported in this paper include the practical reservoir effects of dual porosity, reservoir permeability anisotropy, and fracture face skin effect.
Investigation of Waterflooding and Gas Cycling for Developing a Gas-Condensate Reservoir
Authors: El-Banbi Ahmed H. , Aly A. M. , Lee W. J. , McCain W. D.
Published: December 2007

This paper presents the results of a full field compositional reservoir simulation study that compares the application of waterflooding and gas injection to a rich gas-condensate reservoir. Fluid (water or gas) injection is used to maintain the reservoir pressure above the dew point pressure and prevent condensate dropout in the reservoir. The simulation study shows that water injection is a viable option in producing gas-condensate reservoirs.

The study shows that both water injection and gas injection result in higher recovery factors than normal depletion. Although gas injection showed higher condensate recovery factors, it may not be economical due to the required large initial investment, higher operating costs, and delay of gas sales. For the water injection to be effective, the reservoir should not be flooded completely with water. Rather, the reservoir should be blown-down before water invades the producing wells. Factors that affect the recovery of gas condensate reservoirs under water injection are highlighted. These factors include time to blow-down and imbibition relative permeability curves. Sensitivity analysis results are presented for these factors.

Water injection has a major advantage over gas injection. In water injection produced gas can be immediately sold and compression cost is saved.
Gel Slugs: A Near-Wellbore Pressure-Loss Remediation Technique for Propped Fracturing
Authors: Chipperfield S. T. , Roberts G. A. , Miller W. K. , Vandersypen R. S.
Published: December 2007

A significant factor in the success of propped fracturing is the complexity of the created near-wellbore fracture geometry. This paper discusses the cost-effective use of high viscosity gel slugs to reduce near-wellbore complexity (measured as Near Wellbore Pressure Loss or NWBPL) in a high temperature, hard rock environment to a level acceptable for successful fracture stimulation. Determination of a fluid dependent, acceptable level of NWBPL has been obtained through extensive field measurements. Knowledge of this limit assists in determining where gel slugs are required and whether a gel slug injection can be categorised as a success or failure.

The benefit of using higher viscosity fluids in propped fracture treatments for NWBPL mitigation is well documented. However, in some environments, such as those described herein, use of higher viscosity for the propped treatment would be both cost prohibitive and possibly detrimental to well production. A preferred technique involves the removal of NWBPL with a higher viscosity slug and, once assured of gel slug success through accurate diagnosis, a lower gel loading propped treatment can be conducted.

This paper provides guidelines for field application of the gel slug methodology and discusses its inclusion in a pre-frac injection sequence. Like other NWBPL remediation techniques, gel slugs may not provide immediate positive results. Limitations of this technique and conditions for its appropriate use are also included.
Reservoir Souring in the Caroline Field
Authors: Seto C. J. , Beliveau D. A.
Published: December 2007

This paper presents a novel mechanism for reservoir souring which is based on the evolution of acid gas from sour aqueous phases present in the reservoir. Souring is a widespread phenomenon in seawater floods. The accepted mechanism in these cases is biogenic activity of sulfate reducing bacteria (SRB).

Field data from the Caroline reservoir indicate that it is souring. What is intriguing about this field is that it is being developed via conventional blowdown depletion, which suggests that SRB is not the cause. The mechanism presented is based on the physical principles of Henry's Law, which govern the solubility of hydrogen sulfide (H2S) in water.

Through material balance analysis and reservoir simulation, the Caroline field is presented as a case study where this mechanism is plausible. Reservoir simulation which account for this phenomenon was subsequently used to generate more realistic gas composition, thus optimizing the operations of the $1 billion Caroline facility.
CBM Resource Potential in the Plains Area of Alberta
Authors: MacLeod R. Keith , Cech R. , Hughes Dave
Published: December 2007

The National Energy Board (NEB) forecasts that unconventional gas will be required to meet Canadian demand by the year 2008 and could constitute up to 65 per cent of supply by 2025. Our study of the coalbed methane (CBM) potential for the Plains area of Alberta estimates a constrained gas resource of 187 Tcf of gas-in-place. Our study considered the major prospective coal horizons (Cretaceous to Early Tertiary), as well as the technical and fiscal constraints to development. Cost supply curves for future CBM development provide insight into the gas prices required to meet the NEB s supply deficiency.
Effects of Geologic Variables on Cleat Porosity Trends in Coalbed Gas Reservoirs
Authors: Nelson Charles R.
Published: December 2007

Naturally occurring microfractures, called cleats, provide the permeability essential for bulk fluid flow in coalbed reservoirs. The bulk fluid flow, in turn, is controlled by the cleat properties, specifically their orientation, spacing, compressibility, and effective porosity. A two parameter, geologic process-based model for predicting the effective cleat porosity of coalbed reservoirs was developed from an analysis of cleat property data for San Juan Basin Fruitland Formation coal. The cleat property data indicate that thermal maturation and effective stress act in opposite directions on the effective cleat porosity of Fruitland Formation coal. These two variables are the basis for the geologic process-based model for calculating effective cleat porosity values.
Integrated Field Study for Production Optimization: Jonah Field — Sublette County, Wyoming
Authors: Eberhard M. J. , Mullen M. J. , Seal C. A. , Ault B. P.
Published: December 2007

The Lance formation in the Jonah field is an overpressured, tight-gas sand that requires hydraulic fracturing for economic production. Because of large gross intervals containing several individual sands, limited entry has been the typical fracturing technique. Wells can have more than 30 individual sands that are completed with multiple fracture treatments; however, production log data indicate that only 58% of the perforated sands contribute to production. Production optimization is dependent on improving the percentage of completed pay contributing to production.

A detailed field study was conducted to determine pay identification and best practices for completions. In the study, 44 wells in the Stud Horse Butte area were analyzed. The study comprised detailed log analysis, fracture treatment data, production data, reservoir analysis, and completion practices. Some of the processes used were log normalization, traditional statistical analysis, and reservoir modeling. Log and treatment data were also analyzed with an artificial neural network (ANN).
Design and Interpretation of Long-Term Tests in the Mahogany Field, Offshore Trinidad
Authors: Maharaj S. , Jones J. R. , Mackow H. M. , Lachance D. P.
Published: December 2007

In this paper, we present the details of how four extended well tests in the Mahogany field, offshore Trinidad, were designed, executed, and interpreted. While much of the interpretation for a given test can be done using standard analytical software, we pay special attention to the need for numerical simulations of the measured responses to establish connected volumes and previously unidentified flow barriers.

To establish how long these nine wells can produce the required contract rates and, hence, the required date of renewed drilling, a program for extended well testing was developed. Each well was tested according to the following sequence: clean up flow followed by a stabilizing shut-in period, a forward sequence flow-after-flow ending with an extended flow period, and extended shut-in. The lengths of each of these test sections is planned to vary from well to well but, in general, the entire test sequence was designed to be 35-60 days long. These tests are intended to establish permeability, mechanical and turbulent skin factors, and the areal extent of the sand connected to the test well.
JAPEX/ JNOC/ GSC MALLIK 2L-38 Gas Hydrate Research Well, Mackenzie Delta, N. W. T.: Overview of Field Operations
Authors: Ohara T. , Dallimore S. R. , Fercho E.
Published: December 2007

The Mallik 2L-38 well was drilled in February and March, 1998 to a depth of 1150m at a site located in the Mackenzie Delta, N. W. T., Canada. Undertaken as a collaborative agreement between the Japan National Oil Corporation and the Geological Survey of Canada, the well was conducted as a research and development project with engineering goals to evaluate various technologies fordrilling and coring gas-hydrate-bearing strata. The Mallik site was chosen as it had favorable logistics and was thought to contain a thick interval of gas hydrates between 897 and 1110 m depth. Drilling operations included a surface hole (with 8 coring runs) to 687m for installation of a 340mm surface casing, and a main hole (with 16 coring runs) to the target depth of 1150m. The drilling system utilized a KCl/polymer drilling mud that was cooled to 2°C using a plate type heat exchanger. Drilltreat, a chemical mud additive was used in the main hole to stabilize gas hydrate within drill cuttings and formation sediments. Drilling operations were conducted without any serious hole problems, accidents, or mishaps. However, delays were caused by adverse weather and mechanical problems, causing adjustments in the overall program. Coring in the main hole was particularly successful allowing evaluation of four different core barrels. Gas-hydrate-bearing core was collected in a variety of sediments between 886 and 952m. The excellent condition of the core samples, controlled gas hydrate dissociation within the mud column, and near-gauge hole, confirmed that the combination of chilled mud with Drilltreat performed extremely well.
Forecasting World Natural Gas Supply
Authors: Al-Fattah S. M. , Startzman R. A.
Published: December 2007

World gas supply forecasting has proved difficult because its exploration, transportation, and customer bases are so heavily dependent on fluctuating economic factors. Our recent study showed that the conventional Hubbert model with one complete production cycle is not appropriate for use in forecasting gas production trends for most gas producing countries.

This paper presents our forecast for the world's supply of conventional natural gas to the year 2050. We used a multicyclic Hubbert approach to develop 53 country-specific gas supply models that enable production forecasts for virtually all of the world's gas. The multicyclic modeling approach is presented in a convenient form that makes production data exhibiting two or more cycles easier to model. These models were aggregated to the regional level and to the world level. Supply models for some organizations (e.g. OPEC, non-OPEC, OECD) were also developed and analyzed.

Our results indicate that the world's supply of natural gas will peak in 2014, followed by an annual depletion rate of 1%/yr. A regional analysis indicates that gas production of some regions will peak soon. North American gas production is currently (1999) at its peak. West European gas production is expected to peak in 2002. The countries of the former Soviet Union and Middle East, which comprise about 60% of world's ultimate recovery of natural gas, will be the main sources of world gas supply in the future.
Phase Diagram Optimization in Micellar Systems
Authors: Baviere M.
Published: December 2007

An optimization of micro emulsion compositions is presented for a hydrocarbon/water ratio considered as characteristic. By studying the influence of the main parameters (molecular weight of hydrocarbon and amphiphilic compounds, surfactant to co surfactant concentration ratio, salinity and temperature), the results obtained show an optimal value for each of them, corresponding to the use of a minimal amount of amphiphilic compounds.

An interpretation is given, based on the equilibrium of hydrophilic and hydrophobic tendencies within the surfactant molecule, and supported by interfacial tension measurements in simpler diphasic systems where the partitioning of the surfactant between aqueous and hydrocarbon phases can be determined.

Thus a set of relationships between the parameters is established that may prove useful, from a practical point of view, in the choice of formulations. In particular, solutions are given for high temperature and brine concentration.

INTRODUCTION

Micellar solutions used in enhanced oil recovery present certain difficulties, as regards both their preparation and their application. These difficulties are further increased by economic requirements as the limits imposed by technical possibilities and profitability narrow the field of possible compositions. In the application of this process, guides are therefore required to reach optimal formulations, i. e., in particular, the use of a minimal amount of amphiphilic compounds.

The search for maximal interfacial efficiency of surfactant entails establishing conditions in which there is a maximal concentration at the interfaces. This should take place when the amphiphilic molecule shows minimal affinity in the aqueous phase and hydrocarbon phase simultaneously; the hydrophilic and hydrophobic tendencies are then very close and balance each other. A similar phenomenon appears when a minimal interfacial tension is obtained in the systems composed of a hydrocarbon and a surfactant diluted aqueous solution. The advantage of these systems is that the partitioning of the amphiphilic product is easily measured and the affinity equilibrium thus is well shown.
A Successful Low Tension Waterflood Two-Well Test
Authors: Murphy Charles L. , Thiede David M. , Eskew James O.
Published: December 2007

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

Mobil's Low Tension Water Flood (LTWF) process was successfully tested in the West process was successfully tested in the West Ranch field in South Texas in 1974. The LTWF process reduced the oil saturation to about 5 process reduced the oil saturation to about 5 percent of the pore volume in the swept area. percent of the pore volume in the swept area. Test results show that it is possible to flush reservoir brine from the 41A formation and replace it with low salinity water. Chemical requirements under dynamic reservoir conditions were established.

Introduction

Mobil Research and Development Corp. developed a surfactant waterflooding, improved recovery process to recover oil from reservoirs that are near their conventional waterflood residual oil saturation. This process is based on the use of surface-active chemicals to reduce the interfacial tension between the residual oil and the displacing aqueous phase so the residual oil can be mobilized and displaced from the trapping pore spaces. Mobil calls its surfactant waterflooding process the Low Tension Water Flood (LTWF) process. Variations of the LTWF process have been, or are being, field tested in the Looma Novia field, West Burkburnett field, Salem unit, and elsewhere.

This paper describes a successful, but limited, test of the LTWF process in South Texas in late 1974. The paper summarizes the objectives, results, and major design and operational features of a two-well (injection well, observation well) reservoir evaluation field test performed in the 41A First Stringer of the West Ranch field. The purpose of the test was to determine if portions of the LTWF process would operate satisfactorily in the West Ranch 41A formation, and to assist in the scale up of laboratory data. The results would be used to design a larger-scale LTWF test in the same field.

LTWF Process

Mobil's LTWF process, as applied in the West Ranch field, consists of the sequential injection of six aqueous slugs containing prescribed concentrations of various chemicals. prescribed concentrations of various chemicals. The chemical content of each slug, as designed specifically for the 41A zone of the West Ranch field, and the function of each slug, are detailed in Table 1. The concepts behind Mobil's LTWF process and the role of the different LTWF chemicals and slugs were reported previously by Foster. previously by Foster.
True Expansive Characteristics of Commercially Available Expansive Cement Under Actual Well Conditions
Authors: Beirute Robert M.
Published: December 2007

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

The Western expansion meter (WEM) was utilized to continuously measure the expanding characteristics of commercially available expansive cements under simulated well conditions of temperatures and pressures. A detailed description of the WEM was given in a previous publication. This paper previous publication. This paper deals with experimental results obtained with the WEM. Specifically, the following studies were performed on expansive cements using the expansion meter:Age of the cement sample — Its effect on the expanding behavior.Mixing procedure — Its effect the expanding behavior.Different samples — Reproducibility of the results from batch to batch.Temperature — Effect of temperature on the expanding behavior of neat expansive cements.Retarders — Effect of retarders on the expanding behavior at different temperatures.Effect of raising temperature Expanding behavior under conditions of raising temperatures on retarded expansive cements. Temperature increasing from circulating to static.

Introduction

For years the construction industry has fought the problem of drying shrinkage in concrete. Standard concretes present a reduction in volume as they present a reduction in volume as they dry after setting. This volume reduction can produce cracks in the concrete due to the development of tensile strengths. Expansive cements are manufactured to compensate for this drying shrinkage by expanding during this critical period.

Chemically, expansive cements are similar to regular Portland cements, except for the presence of an anhydrous calcium sulfoaluminate (4CaO.3A12O3.SO3).

This compound, hydrates to form ettringite.
A Novel Approach for Monitoring of CaCO3 and BaSO4 Scale Formation
Authors: Morizot A. P. , Neville A.
Published: December 2007

To date much emphasis on scale inhibitor evaluation and studies of scale kinetics has been given to studies using static beaker tests. This paper describes an electrochemically based technique, which allowed the extent of scaling on a solid surface to be determined in presence and in absence of scale inhibitor. The ability of the technique to provide kinetic information on surface scaling will be demonstrated with two kinds of scale. Finally the potential for this technique as a method for on-line monitoring of scale formation downhole will be discussed.
Comprehensive Evaluation of Fractured Gas Wells Utilizing Production Data
Authors: England K. W. , Poe B. D. , Conger J. G.
Published: December 2007

The ability to determine the effective half-length and conductivity of hydraulic fractures is important for estimating a well's long-term production performance. The determination of these properties, along with the formation effective permeability, can result in more accurate predictions of the ultimate hydrocarbon recovery. In very low permeability reservoirs, fracture half-length is the key to optimum reservoir development. Being able to quantify these properties also allows for improved understanding of the effects of treatment design changes. Post-treatment pressure buildup testing has been the most common method for determining the effective length of hydraulic fractures. One of the major drawbacks of the pressure transient test in very low permeability reservoirs is the extremely long shut-in time required to observe a sufficient amount of the fractured well transient behavior to properly characterize the formation and fracture properties. This long shut-in time is undesirable due to the fact that the well is not able to produce and generate revenue during this time.

This paper reports on the most recent results of an ongoing study of the production performance of hydraulically fractured wells. The focus of the study is a comparison of the performance of conventionally fractured wells and those that have been completed with the treated water and low proppant concentration ("waterfrac") technique. A new evaluation technique for comparing the effectiveness of the treatments utilizing production data is introduced. The advantages and limitations of the production data analysis technique are discussed, as well as an improved understanding of the results of waterfrac treatments in low permeability gas reservoirs.

The use of a comprehensive suite of analysis techniques for the production performance of fractured wells to obtain estimates of fracture half-length, fracture conductivity and formation effective permeability is detailed. Specialized diagnostics, performance history matching with analytic solutions and specialized type curve analyses have been used for several areas to estimate the fracture and formation properties from the bilinear, formation linear and pseudoradial flow regimes.
Future Trends in Supply of Petroleum Engineering Manpower (Glenn)
Authors: Glenn Wayne E.
Published: December 2007

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

Introduction

It is my distinct pleasure to be here with you today to talk on a subject that has great interest for me—petroleum engineering. Having worked as a petroleum engineer for a good part of my oil career and being directly associated as a manager for the remainder of it, I feel a strong sense of allegiance and concern for the future of petroleum engineering. As a discipline, it has had spectacular growth and contributed immensely to the technological capability of our industry. It will influence in large measure where we as an industry will be tomorrow.

Petroleum engineering began to emerge shortly after Drake drilled his first well at Titusville, Pa. Men without formal engineering training began to grapple with problem aspects of drilling, production, and oil reservoirs, which in our day have come to be known as petroleum engineering. A formally taught and petroleum engineering. A formally taught and practiced discipline was not on the oil scene practiced discipline was not on the oil scene really until about 1915. From that time on, it grew rapidly and fostered a breed of men from which much of the leadership for the industry has come. They were and still are a group with great breadth of understanding in relating human problems and skills, economics, risks, technical problems and skills, economics, risks, technical and practical know-how, all of which interplayed to help mold a great and bold industry. It is an industry capable of yielding results against difficult odds generated from complexity and from the physical environment. The understanding of risk and probabilities (generated from natural factors) is a game we must play to be in this business. Over the past 50 yews, we have overcome some risks through new technology, and other risks have cropped up. The net result is that the business is still risky.

A point that consistently emerges is that the best leadership for the production part of the business was and continues to be found in those who have a thorough understanding of all the factors involved in locating, drilling, producing, and employing economic and technical producing, and employing economic and technical analysis of reservoirs. This is the widely accepted broad definition of petroleum engineering.

Since the upstream side of the oil business will continue to drill wells and produce reservoirs for some time to come, there will be a need for experienced oil men to provide leadership, operational know-how and technical and economic assessment.

When we view what is occurring in the oil industry in the United States, we get concerned as to what the future holds.
Enhanced Wireline Formation Tests in Low-Permeability Formations: Quality Control Through Formation Rate Analysis
Authors: Lee Jaedong , Michaels John
Published: December 2007

Wireline Formation Test (WFT) tools are used to measure formation pressures at discrete depths and to obtain fluid samples. From these pressure tests, fluid density and fluid contacts can be derived.

The transient pressure response created by a WFT pressure test has typically been analyzed by methods that originated from well test analysis. In 1996 a new method based on the formation flow rate was developed that simultaneously considers both drawdown and buildup portions of the data. Because the new method is based on material balance from the beginning of the test, it accounts for the storage effect in the tool. By a simple, graphical technique or multi-regression analysis, the method determines fluid compressibility, mobility, and undisturbed formation pressure (P*).

Pressure tests in low-permeability formations have been hampered by problems, such as excessively long buildup time, supercharging, and loss of packer seals. In addition, pressures with insufficient drawdown volume are confused with tight formation tests. These problems result in abandonment of tests or incorrect formation pressures that eventually give false pressure gradients, and waste rig time.

We have analyzed numerous field and test-well jobs and have found that good pressure tests in a low-permeability formation can be achieved in less time by implementing quality control procedures through the new method. The ability to repeat a pressure test provides a good basis for applying quality control measures while logging. When the new method indicates a tight formation for the initial test, the drawdown rate for a subsequent test is controlled to a very low rate (less than 0.5 cc/s) and a real time cross plot of formation rate versus pressure is monitored to ensure the quality of the data.

The new method can also detect tool plugging and the presence of pressure supercharging. These abilities can assess the validity of a test during testing and thereby provide a way to assure that a test is successful.
Pressure Transient Response for a Naturally Fractured Reservoir With a Distribution of Block Sizes
Authors: Spivey J. P. , Lee W. J.
Published: December 2007

A number of authors have questioned the assumption of pseudosteady-state matrix-fracture flow in the Warren and Root model. The assumption of uniform block size has not been investigated extensively, however. The consensus is that fracture spacing, rather than being uniform, follows a distribution similar to an exponential distribution.

This paper examines the effects of an exponential distribution of fracture spacing on the distribution of block size, interporosity flow coefficient, and the resulting pressure distribution. The paper also discusses a number of alternative models for naturally fractured reservoirs that give rise to pressure behavior very similar to that predicted by the Warren and Root model.
Variation in Fracture Permeability in Chalk Core Plugs
Authors: Olsen D. , Nielsen C. M. , Bech N.
Published: December 2007

A miscible displacement experiment where D2O brine was displaced by H2O brine was conducted on a North Sea chalk sample with an induced fracture. The experiment was monitored by a 2D NMR technique. Differential pressure and production of D2O were logged.

The displacement process was a combination of a pistonlike displacement proceeding from the inlet end plane, and a displacement proceeding from the fracture into the matrix. NMR images show large axial variations in the amount of fluid transport across the fracture-matrix boundaries, indicating the presence of a significant permeability variation along the fracture.

The variation in fracture and matrix permeabilities are determined numerically by matching measured and calculated pressure drops, H2O/D2O concentration profiles and cumulative production. An ECLIPSE model with a fracture containing two partial blockages closely simulates the concentration profiles and the production. Calculated results indicate that the permeability at the blockages is below one tenth of the fracture permeability. The pressure drop across the plug increases with time indicating that the degree of fracture blockage is growing with time.
Economic Fracturing of Bypassed Pay: A Direct Comparison of Conventional and Coiled Tubing Placement Techniques
Authors: Marsh J. , Zemlak W. M. , Pipchuk P.
Published: December 2007

This paper presents a study of low-permeability gas wells located in the Rocky Mountain foothills of Alberta, Canada, where production enhancement often involves various stimulation techniques to improve well production. We evaluated conventional techniques to a novel fracturing technique using the latest in fracturing fluid and coiled tubing technologies to concurrently and selectively place fracture treatments into multiple pay zones or stringers.

The coiled-tubing hydraulic stimulation technique was an excellent method for stimulating multi-zone wells, resulting in savings of $300,000 per well on the three Wildcat Hills Viking wells. The minimal operation and improved clean up time accounts significantly in being able to bring the wells on production 4 to 8 days sooner than with conventional methods for multi-zone wells.

Our approach describes the background, history and the impact of our successful utilization of coiled-tubing technology to convey hydraulic fracturing in the Wildcat Hills. The impressive benefits of this alternate and selective approach is improved control of net height and optimized effective fracture length. In addition to the substantial return in favorable production and economics, the design is acceptable for use in the ecologically sensitive area of the Canadian Rockies.
Acquisition, Calibration, and Use of the In Situ Stress Data for Oil and Gas Well Construction and Production
Authors: Avasthi Jitendra M. , Goodman Harvey E. , Jansson Ray P.
Published: December 2007

In situ stress data plays a vital role in various stages of oil and gas well construction and production, such as drilling, well completion, well stimulation, production, and waste reinjection. But generally, its acquisition does not receive as much attention as it deserves, and some times no attempt is made to collect this significant information. Most of the time lack of this information is compensated by the guess or indirect stress related information. This situation is evident from the scarcity of directly measured stress data in oil and gas fields throughout the world. Within Chevron, we have used open hole log data, pore pressure measurements, leak-off tests, formation integrity tests, mini-frac tests, drilling performance data, and caliper data to decipher in situ stress information. The collected data is calibrated using an open hole log based algorithm, linking stress profiles, mechanical properties from core tests, mini-frac and drilling performance data. In situ stress data provides valuable insight into wellbore stability problems, fine tuning fracture stimulation designs, the prediction of sand production, and to analyze the waste (drilling mud and cuttings) injection situations into selected formations. Essentially, the strong linkages created between various engineering applications are put to practical use in constraining the earth stress solution. This approach helps ensure that the final product is an integrated solution that solves the well design problems at hand. This paper discusses various aspects of in situ stress data acquisition, calibration, and use within Chevron with relevant field examples.
Reduce Power and Maintenance Costs of Power Fluid Conditioning Units by Improving Overall Operations
Authors: Justus Marvin W.
Published: December 2007

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

Single-well hydraulic pumping units are commonly called Power Fluid Conditioning Units (PFCU). The power cost per barrel of fluid lifted with a PFCU was reduced significantly by the installation of a four-speed transmission and a new style low-volume subsurface pump. The changes provided the flexibility necessary to obtain economically maximum production from both low and high volume wells.

The hydrocyclones were resized for proper operation which reduced the volume of abrasive solids in the power fluid. When the solids load was reduced, the operating life of the hydraulic pump and engine was increased.

Introduction

Presently, in a West Texas oil field, there are 39 single-well hydraulic pumping systems in operation. A single-well hydraulic pumping system contains two basic components, a surface unit and a subsurface unit. The surface unit consists of a high pressure multiplex pump, volume tank and solids removal device. The subsurface equipment includes a reciprocating positive displacement hydraulic engine which is positive displacement hydraulic engine which is direct-connected to the reciprocating production pump. High pressure fluid from the surface pump pump. High pressure fluid from the surface pump actuates the subsurface engine and pump.

Approximately 56 percent of the units are considerably oversized for the present producing rates. The multiplex pump is powered with a direct-drive electric motor. Therefore, if the subsurface pump is oversized for the fluid producing capacity of the well, a portion of the producing capacity of the well, a portion of the high pressure power fluid is bypassed and power is wasted. The units are installed in a relatively new secondary recovery project; therefore, the fluid production of the wells is expected to increase. Until the anticipated production increase is realized, modification of equipment is required for the reduction of excessively high power and maintenance costs.

The first consideration was to reduce the amount of bypassed, pressured power fluid. Five different methods were evaluated.Change existing gear ratios in the original gear reducer.Change plunger sizes in the multiplex plunger power fluid pump.Add belt drive speed reduction.Remove one plunger from the multiplex pump.Add a multi-speed transmission between the motor and pump.
Three-Phase Oil Relative Permeability Models
Authors: Dietrich James K. , Bondor Paul L.
Published: December 2007

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

Two variations of an indirect technique for predicting three-phase oil relative permeability are described in this paper. permeability are described in this paper. Relative permeabilities and the dependence of waterflood residual oil saturation on trapped gas saturations predicted by these two models are compared with the three-phase experimental data available in the literature.

Both models provide acceptable schemes for interpolating in the three-phase region, and qualitatively match the curvature of isoperms generated in the more carefully conducted (and previously published) threephase experiments.

Limitations of each model are described, including the need for establishing derivative constraints to prevent calculation of relative permeabilities greater than unity. Guidelines are also presented for determining which model should be used in specific applications.

Introduction

Thorough analysis of a displacement process in which three-phase flow predominates process in which three-phase flow predominates (viz. steam drive and alternate gas/water) requires three-phase relative permeability data. The effort involved in determining these data experimentally suggests that indirect methods should be investigated. The difficulty in direct experimental work lies mainly in determination of saturation distributions along the length of the core. Electrical resistance circuits and either gamma-ray or x-ray absorption techniques are required to measure two of the three saturations in a three-phase system. Only nine experiments concerning three-phase relative permeability have been found in the literature.

As an alternative to the direct methods, Stone has suggested that more easily measured two-phase data can be used to predict relative permeability to both the predict relative permeability to both the wetting and nonwetting fluids in three-phase flow. Then an indirect approach involving a technique which uses two sets of two-phase data-water/oil and gas/liquid - can be used to predict the relative permeability of the predict the relative permeability of the intermediate wettability phase.

THE TWO RELATIVE PERMEABILITY MODELS

Two variations of the indirect technique are described here. The first is a three-phase oil relative permeability expression developed by Hirasaki. This is a modification of a model originally proposed by Stone in 1970. The second model was presented in a paper by Stone during 1973, as a revision paper by Stone during 1973, as a revision of his first technique.

Model I

It has been observed experimentally in water-wet systems that the water relative permeability is approximately only a function of permeability is approximately only a function of the water saturation, and that the gas relative permeability is approximately only a function of permeability is approximately only a function of the gas saturation.
Casing Stresses Caused by Buckling of Concentric Pipes
Authors: Christman Stan A.
Published: December 2007

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

A technique is developed to analyze the buckling stability of multiple, concentric pipes If the system is unstable and buckles against a lateral support such as an irregular open hole, an estimate is made of the elastic stresses and pipe curvature. Example applications are pipe curvature. Example applications are presented in offshore platform wells, in floating presented in offshore platform wells, in floating drilling, and for partially cemented surface casings.

Introduction

In the design of oil and gas wells, it is often necessary to consider the stability (tendency to buckle) of casing and tubing. Previous literature has shown methods to Previous literature has shown methods to determine the stability of a single pipe under complex loadings, and methods are available to determine the resulting geometry and stresses of a pipe which has elastically buckled into a helix inside of a uniform outer pipe.

The technique in this paper describes the behavior of a system of concentric pipes. It further provides an approximate calculation methods of the system geometry after helical buckling has occurred against a lateral restraint of non-uniform diameter.

Three example applications of the concepts are given:The effect of drill pipe tension on the stability of a marine riser in floating drilling,the required spacing of lateral supports for oil-well conductors on an offshore platform, andbuckling of an oil-well casing nest against a partially uncemented open hole.

Stability of Concentric Pipes

The following derivation shows how the tensions and compressions of the individual pipes contribute to the overall stability of a multiple pipe system. Specifically, the stability load pipe system. Specifically, the stability load of the system is shown to be the arithemetic sum of the individual loads (Eq.1), and the total system stiffness is the sum of the individual moments of inertia (eq. 2).
Prediction of the Permeability of a Fragmented Oil Shale Bed during In - Situ Retorting with Hot Gas
Authors: Needham R.B.
Published: December 2007

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

The operability of in-situ oil-shale retorting has been established by retorting beds of crushed shale under lithostatic loads simulating the column loads to be encountered in practical operations. The resulting compaction practical operations. The resulting compaction and reduction in permeability were correlated to predict the final permeability behavior of an actual fragmented in-situ bed with particles averaging 6 in. in diameter.

Two compaction cells, 1.25 and 5 in. in diameter, were used for the retorting experiments in which the permeability of the compacted bed was determined for average shale particle size from 0.046 to 1.0 in., shale richness from 18 to 58 gal/ton, lithostatic load from 70 to 900 psi and heating rate from 5 to 100 deg. F per hour. A correlation was developed that predicts the permeability using the lithostatic pressure, shale richness, and particle size for a shale heating rate of 10 deg. F per hour. The modified Kozeny equation was used as the theoretical basis for the correlation and the measured permeabilities could be predicted with an permeabilities could be predicted with an average error of 21 percent.

Introduction

The initial permeability of an in-situ bed of broken shale will be more than adequate for the injection of heating fluids, but retorting drastically reduces the permeability as a result of compaction caused by heating the oil shale under an overburden load. To estimate the permeability of the fragmented shale bed during permeability of the fragmented shale bed during retorting, the influence of shale particle size, lithostatic pressure, temperature history, and shale richness was determined by laboratory experiments. These experimental data were correlated and then extrapolated to a larger average particle size to predict the permeability of fragmented shale beds anticipated for commercial in-situ retorting. Green River oil shale from the Piceance Creek Basin in Colorado was utilized throughout these studies.

EXPERIMENTAL APPARATUS AND PROCEDURE

Large-Scale Compaction Cell

A simplified sectional view of the large-scale compaction cell is shown in Fig. 1. The cell is cylindrical and holds about 5,000 to 7,000 gm of crushed shale, depending upon the shale richness.
Engineering the Oil Loan Under Conditions of Economic Uncertainty
Authors: Miller Richard J.
Published: December 2007

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

The paper examines the impact of current petroleum economics on the valuation procedures used by banks to determine the value of oil and gas properties for production loan purposes. properties for production loan purposes. In the past determination of collateral value and debt repayment ability was generally made using rule of thumb methods derived from actual lease sales during periods of economic stability. Increasing oil prices, FEA price regulations, and cost inflation have made former rules unreliable for determining current property values. The paper studies the Rate of Return discount method as a means of relating Fair Market Value determinations to prevailing economic conditions.

The paper expands on previous work by developing a variable discount rate system for determination of the appropriate Rate of Return for discounting. The variable system combines long-term projections of prime lending rate and projections of prime lending rate and investment interest rate with historical industry earning trends. The variable system allows the Rate of Return method of valuation to be applied to all properties regardless of economic category properties regardless of economic category or location. The addition to the system of lending and investment rates in foreign countries along with a country risk factor allows the variable rate approach to be used in foreign property valuations.

The techniques described in the paper are primarily designed to provide the production loan borrower a means of production loan borrower a means of evaluating the financing potential of his existing properties. Secondary applications include the general determination of the value of properties for sale or acquisition. The paper concludes that traditional rule of thumb models based on historical lease sales are unreliable in terms of prevailing economic conditions and both domestic and foreign regulation and tax structures.