bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overpressure Calibrated Design of Hydraulic Fracture Stimulations
Authors: Shlyapobersky J. , Wong G. K. , Walhaug W. W. 
Published: December 2007

ABSTRACTThis paper presents a new concept, model, and procedure to design hydraulic fracturing treatments. The purpose of the paper is to develop an approach in designing hydraulic fracture stimulations that would be more consistent with field observations and would better match the field net fracture propagation pressure.The concept and procedure consist of using the net fracture pressure measured shortly after shut-in (overpressure) to determine the apparent fracture toughness (Γ or K1c) of the formation. This field calibrated K1c or overpressure is then used as an input to an approximate hydraulic fracture simulator, called ENERFRAC, to design the hydraulic fracture stimulation volume and proppant injection schedule.The field overpressure needed to determine the K1c can be accurately measured using a minifrac test. The overpressure is defined as the difference between the corrected instantaneous shut-in pressure and the minimum in-situ stress. Frequently, the field calibrated K1c could be one to two orders of magnitude larger than those measured in the laboratory using small samples. This high value of K1c is attributed to the field and scale dependent process zone at the fracture tip.The field calibrated K1c could dominate the fracture growth and needs to be included in the hydraulic fracture model to predict realistic fracture dimensions. This paper provides an approximate model, called ENERFRAC, that incorporates the effect of K1c in addition to the other interacting processes of viscous fluid flow, elastic rock deformation, and fluid loss in the conventional models of contained and uncontained fractures.This paper outlines the procedure for the overpressure calibrated design and provides three field examples to illustrate the design procedure and to show the effect of designing with and without overpressures. Examples of treatments that are more aggressive (with smaller pad and larger amount of proppant) or more conservative (with larger pad) than those generated by the Khristianovic/Geertsma/deKlerk model (KGD) are presented. Thus, the proposed overpressure calibrated design not only provides a stimulation that is more consistent with field observations but may also reduce the risk of premature sand-out.
The Effect of Flow From Perforations on Two-Phase Flow: Implications for Production Logging
Authors: Zhu Ding , Hill A. D. 
Published: December 2007

ABSTRACT
The phenomenon of a dense phase (water) entering through perforations into a stream of a less dense phase (gas or oil) has been examined in a model wellbore. When water entered a gas stream, some of the water fell through the gas stream to occupy a portion of the wellbore below the perforations for all conditions tested and anomalous pressure behavior was observed in the region of the perforations. In the oil-water tests, all of the water was swept upwards by the oil only at the highest oil flow rate (5000 b/d) and lowest water flow rate (50 b/d) with the pipe vertical. The deleterious effect of dense phase fallback on production log interpretation is demonstrated.
Production System Optimization: Model Applications, Capabilities, and Pitfalls
Authors: Iyoho A. W. , Lea J. F. 
Published: December 2007

ABSTRACTThis paper discusses the state of the art in total production-system analysis useful for economical design of well inflow parameters, sizing of tubulars and accessories, and determining well flow constraints. In addition, capabilities and pitfalls are cited in model applications.To bridge the gap between model developers and users, the structure of a typical computer program is discussed. Field cases are then used to emphasize good geological and engineering practices as opposed to total reliance on model results. Applications of optimization programs to naturally flowing wells, wells on pump, gas-lift wells, and fractured wells are presented, with emphasis on greater technical cooperation. The beam-pump and injection-well examples presented in the paper should be particularly interesting since these areas have seen limited total-system analysis.Major conclusions are that the total system approach can provide important analytical answers to production problems. However, model application must be combined with sound technical and economic judgement, and a willingness to cooperate with geologists and engineers from all disciplines, to realize its full potential.
Successful Water Control Examples in Gulf of Mexico Gravel Packed Gas Completions
Authors: Carroll J. F. , Bullen B. 
Published: December 2007

ABSTRACT
Numerous methods of water control have been attempted in gravel-pack completions. Many of these methods utilize predesigned hardware to plug off anticipated sources of future water production. The problems associated with these methods include predictions of reservoir performance and the extra expense and installation of the completion hardware necessary to achieve future predicted water production. Other methods of water control use chemical injection treatments. These treatments are usually expensive and hard to control.
Laboratory tests were made to evaluate a new method of controlling fluid migration in an internal gravel-pack completion. Production data which confirm the success of this method in the Gulf of Mexico are presented.
Casinghead Gas Processing at the Belridge Field
Authors: Jan R. J. , Reed T. G. 
Published: December 2007

ABSTRACT
Thermal enhanced recovery has been practiced at the oil fields near Bakersfield since late 1950s. Typically, 600 to 700 psig steam, at about 70 to 80 % quality is injected into the formation to heat the oil and to drive the oil to the producing wells.
The injection of steam results in the formation of various gases in the formation which are produced as casing head gas. Because of it's low heating value, it is also called waste gas. Typically, the gas is saturated with steam, has a composition of about 80 % CO2, with up to 5 % H2S and a heating value of between 200 to 500 BTU per cubic foot.
Environmental regulation in California dictates that the casing head gas cannot be vented to the atmosphere but must be gathered and disposed of. Normally entrained oil and condensate are removed before final burning in an inc inerator.
A process has been developed and implemented at Mobil's Belridge field whereby up to 5 MMSCFD of waste gas is gathered, treated, and blended with fuel gas which is burned in the steam generators. The blending of gases has become an integral part of the operation and quality control of a steam generator through a Programmable Logic Controller.
The system has been in service for two years. Savings in operating cost alone has more than paid for the initial capital investment. Further, the simplified system design has lowered the wellhead casing pressure and resulted in an increase in the oil production.
Effects of Wellbore Pressure on Perforator Penetration Depth
Authors: Behrmann L. A. , Halleck P. M. 
Published: December 2007

ABSTRACT
Industry has generally assumed that perforator penetration depth is independent of wellbore pressure. However, recent test data clearly show that modern perforator penetration performance is significantly affected by wellbore pressure. Two series of tests were performed using unstressed and stressed Berea sandstone. The unstressed tests used modified API Section II Berea test targets with wellbore pressure equal to pore pressure. Three different perforators at a 0.75-in. gun-to-casing clearance were tested. The penetration reduction from ambient to 15,000 psi wellbore/pore pressure was charge dependent and ranged from 22% to 28%.
Tests with nonequal wellbore and pore pressures in unstressed Berea targets showed penetration reduction to be independent of pore pressure.
Test of a single perforator in stressed Berea at an effective stress of 2000 psi also showed penetration reduction with wellbore pressure. This penetration reduction suggests that for the perforator tested, wellbore pressure may be a more dominant effect than in situ stress for deep wells.
Exploitation of Deeply Buried Coalbed Methane Using Different Hydraulic Fracturing Techniques in the Piceance Basin, Colorado and San Juan Basin New Mexico
Authors: Jeu S. J. , Logan T. L. , McBane R. A. 
Published: December 2007

ABSTRACT
This paper reports on observations of hydraulic fracturing in coal seams gained in research activities, conducted by Resource Enterprises, Inc. and sponsored by the Gas Research Institute in their Western Cretaceous Coal Seam Project. The fracture treatments span a period from 1986 through 1988 and involve activities in the Piceance and San Juan Basins. Findings resulting from this work are that hydraulic fracture designs must reflect the lithology of the bounding strata as this affects fracture height growth and fracture geometry. Where coal seams are adjacent to sandstone, diagnostics show that hydraulic fracture growth occurs in both the sandstone and the coal and fracturing pressures are less than 1.1 psi/ft. It was also demonstrated that a linear fracture fluid could be used effectively to place proppant in the coal zone if the sandstone overlies the coal. Much higher treating pressures were encountered in fracture treatments where coals were bound by shale. Diagnostics showed the fracture to be contained primarily to the coals and the high treating pressures may have resulted in part from a complex fracture geometry. Several possible reasons for this behavior are listed. High strength casing was found to be useful in accommodating the higher treating pressures and it allowed a larger treatment to be pumped where many jobs have had to be terminated prematurely when the burst strength of the tubulars was reached. Higher injection rates and the use of solid fluid loss material are recommended to create sufficient width in the complex geometry and thereby increase the likelihood of a successful treatment. Caution is advised in the use of conventional interpretations of Nolte-Smith (log net pressure vs. lot time) plots because of the abnormally high treating pressures associated with coal and the potentially-complex fracture geometry that have been observed in mineback experiments are well beyond the scope of the simple Nolte-Smith technique.
Ekofisk Formation Pilot Waterflood
Authors: Sylte J. E. , Hallenbeck L. D. , Thomas L. K. 
Published: December 2007

ABSTRACT
This paper describes the design, operation and evaluation of a pilot waterflood project initiated in the Lower Ekofisk Formation of the Ekofisk Field located in the Norwegian sector of the North Sea. Previously, a pilot waterflood project in the Tor Formation led to approval in 1983 of full scale water injection in the Tor Formation.
The Ekofisk and Tor Formations are both low matrix permeability chalks characterized by intense natural fracturing. This natural fracturing has enhanced overall permeability and made commercial production possible from these volumetric solution gas drive reservoirs. The Ekofisk Formation was initially given lower waterflood priority based on spontaneous imbibition laboratory experiments. However, the large values of initial oil in place, in combination with the recognition that mechanisms other than imbibition may play a role in waterflood performance necessitated a pilot be performed. Additionally, the pilot was designed to evaluate rock stability and injectivity in this fractured chalk reservoir.
The pilot project consisted of one injector and three producers in an unconfined four spot pattern. As of May 1988, a total of 10 million barrels of water had been injected over a 22 month period. Results have been favorable and have been utilized to justify expansion of the waterflood to the Lower Ekofisk Formation.
Factors which were taken into consideration during the analysis include lack of both vertical and horizontal confinement, significant initial gas saturation, influence of gas injection, regional permeability variations, anisotropy and layering effects. Three dimensional simulation results are included which tie all the parameters together and form the basis for extrapolating results to full field.
Productivity of a Horizontal Well
Authors: Babu D. K. , Odeh A. S. 
Published: December 2007

Abstract
Two appendices describe the mathematical and algebraic details that led to the formulas provided in the text of this paper. Appendix A presents the general solution, and briefly describes the techniques for deriving simple, closed form expressions for single, double, and triple sums of infinite series. Appendix B describes these procedures in a little more detail, and also indicates certain methods for averaging the variable wellbore pressures in the general anisotropic cases.
Uniform Flux Boundary Condition
For well problems similar to the one treated in this paper, a uniform flux, or a uniform pressure is commonly imposed as a boundary condition at the well surface. Recognizing that neither is entirely correct, the question that has been debated is whether one is preferable to the other, or whether both give satisfactorily accurate solutions. Muskat(7) shoved that the uniform flux boundary condition gives values accurate to 0.5 percent. We also investigated the implication of the uniform flux assumption. We used our exact solution (Equations A1–A3) and computed the wellbore pressure, pwf at various locations y along the well length L. We did this for isotropic and anisotropic systems where the wells were located at the center, or away from the center. For the anisotropic runs the value of kz was equal to, or twice as large as, that of ky, and was ten times that of kz. Also L/b-0.5. We found that the maximum variation in pwf values was 7 psi for the worst case. This was the anisotropic case with kx=2ky, kx=10kz, and the well was located away from the center. For the other cases, the variation was less than 3 psi. Since one expects pwf to be of the order of several hundred, if not thousand pounds, we concluded that the uniform flux assumption resulted in approximately uniform pressure. Therefore, we expect a uniform pressure boundary condition to result in approximately uniform flux. Thus we concluded that these two boundary conditions lead to approximately the same solution.
Treatment of Anisotropy
As described in some detail in Appendix B, permeability anisotropy introduces angular dependence of wellbore pressures in the vertical (x=z) plane. This angular dependence can be removed by an averaging procedure, and the averaged pressure is identical to that of an equivalent isotropic reservoir with scaled dimensions. It is also indicated in Appendix B that this average pressure is the actual pressure measured at an angle θ given by: θ=are tan (kz/kx)1/4 from the x-axis. In much of the subsequent work in this paper, computations and derivations will be performed assuming homogeneity and isotropy. However, the final results will be expressed in terms of the permeabilities (kx, ky, kz) for the general anisotropic reservoir. Furthermore, it will be assumed that the pressures are computed at an angular position of θ=[are tan(kz/kx)1/4] on the well perimeter in the general anisotropic cases.
Coiled-Tubing-Conveyed Logging Systems
Authors: MacEwen H. 
Published: December 2007

ABSTRACT
Traditional logging techniques for highly deviated and horizontal wells are increasingly becoming a matter of concern to operators. One of the major difficulties has been the special equipment, time and associated cost required to place the logging string on bottom and log or perforate a zone of interest.
Coiled-tubing-conveyed wireline logging and perforating tool strings are now proving to be a quick, cost-effective, accurate method of logging these wells with difficult deviation profiles.
The paper outlines the development and current capabilities of the system, including the computer modelling which takes place before each job to design the operating limits necessary to avoid buckling the coiled tubing downhole. Results of the first field applications using the system are presented; specialist applications, including PLT surveys of wells using gas as a lift medium while logging, are discussed.
Reservoir Simulation Applied to the Development of the Magnus Field
Authors: Wood A. R. O. 
Published: December 2007

ABSTRACT
The Magnus field, which is the most northerly developed field in the North Sea, was discovered in 1974. Appraisal drilling during 1976 and 1977 confirmed the presence of a major oil field. The development plan for the Magnus field was approved by the UK Government in December 1978, but was modified in December 1982 following further drilling.
The emplacement of a single steel platform jacket in Magnus was successfully completed in April 1982. First oil production from satellite wells tied to the platform by subsea pipelines, began in August 1983. The water injection system was commissioned in mid 1984 when the first well was turned around to injection. By the end of 1987 a total of 19 development wells had been drilled and the field had produced 195 million stb from estimated reserves of 665 million stb.
This paper describes the reservoir simulation studies conducted to support the development of Magnus. Reservoir simulation played a significant role in designing the original development and modifying it as it has proceeded.
The Evolution and Future Trends in Remote Subsea Maintenance
Authors: Rule D. D. , Rickey W. P. 
Published: December 2007

ABSTRACT
An approach to maintenance has a very fundamental effect on the configuration of a subsea production system and more significantly on the investment and operating costs of that system. As subsea production techniques have developed, a variety of maintenance philosophies have been utilized ranging from dedicated manipulators to ROVs and including either modular and/or component approaches for manifolds and wellheads and TFL or wireline techniques for downhole work.
This paper describes the evolution of these remote techniques from the earliest drilling based approaches to the latest philosophies employing the current generation of commercially available ROVs and workboats of opportunities. It will compare approaches suitable for large multi-well templates as contrasted with the marginal single well satellite and discuss the effects of enhanced reliability versus maintainability. Specific examples, including the Exxon SPS, the Zinc project, and the Exxon Deepwater Integrated Production System (EDIPS) R&D project will be examined.
Future trends are discussed with particular emphasis on the role of ROV versus diver assisted techniques in more moderate water depths.
Multiphase Technology: Is it of Interest for Future Field Developments?
Authors: Furuholt E. M. 
Published: December 2007

ABSTRACT
Multiphase transport systems are already commonly in use for short transport distances or "pleasant" fluids. Application of multiphase technology in field developments may result in 10-40% reduction of investment costs. An unmanned wellhead platform combined with multiphase transport may be equally cost-effective as a subsea system, even in large water depths. The main technical problem areas are discussed and some conslusions are drawn as to the future use of multiphase technology.
Reservoir Modeling of Low-Sinuosity Channel Sands: A Network Approach
Authors: Martin J. H. , Evans A. J. , Raper J. K. 
Published: December 2007

ABSTRACT
The prediction of sand body connectivity at an appraisal stage is vital for planning development of channelised fluvial reservoirs. There has been recently considerable interest in the use of stochastic techniques to model channel sand body distributions. However, several problems are encountered. These include: othe uncertainty of geological input dataothe difficulty of honouring specific well dataothe large number of realisations which may be needed to quantify possible reservoir performance.
We present an alternative deterministic approach, based upon geological modelling, well test analysis and simulation. This relies on the concept that localised channel systems can be expanded to represent an extensive regional network. An areal description of reservoir transmissibility anisotrophy, readily accommodated in conventional reservoir simulation grids, is generated by deriving equivalent channel dimensions and flow characteristics and by defining distances between channel interconnections (repeat lengths).
The technique is applied to the Lower and Middle Statfjord units of a North Sea (Norwegian Sector) field.
Safety Valve Technology for the 1990's
Authors: Going W. S. , Pringle R. E. 
Published: December 2007

ABSTRACT
Searching for petroleum continues to encounter more challenging environments both at surface and subsurface with new demands on equipment. Subsurface safety valves for the 1990's environments are designed and developed today with deep setting capabilities, pressure ratings, material technologies and special features that were unavailable five years ago. This paper presents safety valve designs that are now in operation having no setting depth limit, others solving high- temperature and high pressure problems. An equalizing safety valve that out-lasts workover programs with new technology in an energy dissipation feature is presented as well as a valve to operate in 800°F temper?atures in steam injection applications. A liquid level controlled valve set at packer depth eliminates well killing when tripping pipe for electrical submersible pump repairs.
An Implicit in Pressure and Saturations Approach to Fully Compositional Simulation
Authors: Quandalle P. , Savary D. 
Published: December 2007

ABSTRACT
This paper presents a consistent implicit in pressure and saturations approach for solving the equations of a fully compositional, isothermal, three phase, numerical simulator. It is based on an original choice of the primary variables for which the partial derivatives for all the pertinent equations are written. For three phase flow (oil, gas, and water) of water plus Nc hydrocarbon components, the primary variables are the pressure P, the water and gas saturations Sw and Sg (Sw and one compositional variable Co for single phase oil or gas), plus Nc-2 compositional variables Ci. A given set of Ci variables characterizes the composition of the oil and gas phases in thermodynamic equilibrium at pressure P, in the Nc component system. Their choice as well as their use with a cubic equation of state are discussed in the paper.
This new approach is supported by a simulation test and is shown to be a suitable compromise between the explicit scheme, which lacks numerical stability, and the fully implicit scheme for which computer time and memory requirements may be prohibitive as the number of hydrocarbon components increases.
Two Models for the Waterflooding of Naturally Fractured Reservoirs
Authors: Douglas J. , Arbogast T. , Purdue U. , Leme P. J. Paes 
Published: December 2007

Abstract
Two models are described to simulate the waterflooding of a naturally fractured reservoir. The first is the relatively standard double porosity model in which the matrix is a distributed source to the fracture system. We explicitly describe the influence of the fracture system on the matrix by imposing the proper boundary conditions on the matrix equations. The second model is a limit form of this model for small matrix blocks. It assumes a capillary equilibrium between the matrix and fracture systems. Finite difference procedures are given for these models. These procedures completely separate the matrix block calculations from the fracture calculations. Numerical results are presented to illustrate and contrast the two models.