bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Production System Analysis to an Offshore Oil Field
Authors: Ueda Y. , Samizo N. , Shirakawa S. 
Published: December 2007

ABSTRACT
Total production analysis is currently in use in oil field operations assisting the optimization of production to ensure the maximum profitability.
The Khafji Field, being an oil field situated in the offshore Saudi Arabia, has been producing oil from more than 100 wells for the past 30 years. Oil flows from the wellhead jacket to the two-phase separator on the offshore flow station (gas oil separation platform). After flowing to the pump station oil is transmitted through the transmission line to the onshore facilities. Some wells are gas lifted and the production water cut is on the increase. Water cut will definitely intensify with the increase in gas lift operation. The review and evaluation of the offshore facilities, from the individual wellhead to the inlet of offshore separator, is essential so as to optimize oil production.
This paper outlines the field application of production system analysis. The flow through the wellhead choke and the flow through the pipeline have been investigated using actual field data and the technical correlation for these flows have been established. A review discussion is offered concerning the identification of the bottleneck in the existing production facilities which at present time, acts as a serious restraint on oil production. The problems encountered in carrying out this investigation are outlined and, specifically, the solution for the bottleneck problem to optimize production within the limits of existing facilities are discussed at length. Finally guidelines are proposed for future facility design and modification.
Numerical Simulation of Horizontal Wells
Authors: Babu D. K. , Odeh A. S. , Al-Khalifa A. J. , McCann R. C. 
Published: December 2007

ABSTRACT
An analytical equation for calculating horizontal well pressure in a simulation model is derived. This equation is very essential for history-matching and predicting the performance of horizontal wells.
The derived equation is needed to compute the effective radius which relates the wellbore pressure to the wellblock pressure. The equation is general and is valid for vertical and horizontal wells, for any well location and for any anisotropy. This equation may substitute Peaceman's equations which need modifications in anisotropic grids of high aspect-ratio (typical of horizontal wells). Simplified forms of the equation applicable to special cases are also reported.
Cycling Fractured Reservoirs Containing Volatile Oil: Laboratory Investigation of the Performance of Lean Gas or Nitrogen Injection
Authors: Thiebot B. M. , Sakthikumar S. S. 
Published: December 2007

ABSTRACT
A laboratory technique has been successfully developed to perform gas gravity drainage experiments under reservoir conditions in three dimensions, that is on cylindrical cores having both lateral and horizontal faces open to flow.
As an application to a light oil reservoir, a series of experiments has been performed on outcrop cores of various permeabilities, in order to compare the efficiency of methane or nitrogen injection. In a first step, cores were saturated with connate water and volatile reservoir oil and subjected to gravity drainage by injection of a rich gas in thermodynamic equilibrium with the oil phase. In a second step, either methane or nitrogen was circulated around the cores, yielding substantial additional recovery of liquids.
The results obtained clearly indicate that:
– During the first step, recovery was essentially the same as in one dimension experiments (lateral faces coated). – Both methane and nitrogen exhibit fast and complete recoveries of light and intermediate components and appreciable amounts of the heavy end fraction. Kinetics of hydrocarbon recovery is strongly dependant on the nature and the injection rate of the gas injected. – An increase of pressure was investigated during gas injection, which exhibited a favourable effect on the heavier components recovery by methane. This influence was much less pronounced for nitrogen injection.
The laboratory experiments were interpreted with a fully compositional simulator. This confirmed the predominant role of vaporization and molecular diffusion.
Water Quality Requirements for Fractured Injection Wells
Authors: Clifford P. J. , Mellor D. W. , Jones T. J. 
Published: December 2007

ABSTRACT
Field measurements of water quality, together with an assessment of the role of thermally induced fractures, indicate that stringent fine filtration requirements are often not required for water injection wells. Corrosion and scaling of tubulars are shown in some cases to result in a bottom-hole quality worse than raw intake water. Well performance, however, is not seen to deteriorate significantly as a result. The reasons for this are examined by the inclusion of fines in models of injection well fracturing.
Installation and Implementation of a Supervisory Control System
Authors: Pearson W.G. , Troiani L.R. 
Published: December 2007

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

Abstract
The installation and implementation of a large supervisory control system, comprising 500 or more producing wells and ten or more remote telemetry stations, is a major undertaking effecting changes in producing equipment, operating organization and communications. The best approach towards achieving the economic incentives of such a system, smoothly and rapidly, is through detailed coordinating and planning.
Decisions regarding the concepts of installation and operation, plus an approach to the selection of personnel, training of personnel and the development of a working organization are presented. Major problem areas encountered in presented. Major problem areas encountered in the system implementation are presented.

Introduction
It is the intention that this paper be a companion paper to SPE 2143 "Feasibility Study of oil Field Automation." The shaded area of Figure 1 refers to material to be covered by this paper. paper. Who should be responsible for system installation? Once the decision is made to install a large supervisory control system, this is the first major decision to resolve. The initial reaction to this question is almost certain to be somewhat like the following statement. "I think we should find a prime contractor for the project and give it to them on a turnkey basis for we don't have the technical knowledge within our organization to do the job." The reason stated for the conclusion may be true, but following this approach will only lead to trouble.
WHO SHOULD UNDERTAKE SYSTEMS RESPONSIBILITY?
There are four potential sources for the assignment of systems responsibility - the telemetry system supplier, the computer system supplier, a consulting engineering firm, and the company production operating organization. In the cases of the first three, a turnkey contract with a prime contractor is the means to achieve systems engineering for the project. If the company chooses the apparent easy way out by letting a turnkey contract, a number of obvious advantages are obtained as follows:
One or more areas of specific technical knowledge in telemetry systems, computers and computer programming can be manifested within the prime contractor.
Evaluation of Jurassic Arab D Reservoir Quality in Low-Relief Traps in Qatar
Authors: Wilson E. N. 
Published: December 2007

Abstract
This study documents petrophysical changes in the Arab D reservoir in Qatar that affect trap configuration and hydrocarbon accumulation in subtle structures with approximately 100 ft (30m) of vertical relief. Two facies have been identified from well data as capable of sustaining producible oil saturations under these conditions. These are clean grainstones and massive permeable dolomites. Analysis of capillary pressure curves indicates that the interbedded packstones, wackestones and mudstones of the Arab D will act as waste zones with a 100 ft (30m) oil column. The distribution of the highly porous grainstone facies is controlled regionally by paleobathymetry, but is unpredictable from well control on the prospect scale. Areas of high porosity can be identified seismically using acoustic inversions. However, seismic data cannot be relied upon to delineate permeability trends.
Stratigraphy of the Wajid Sandstone of Southwestern Saudi Arabia
Authors: Evans D. S. , Lathon R. B. , Senalp M. , Connally T. C. 
Published: December 2007

ABSTRACT
Until recently, the relatively monotonous, thick sequence of Wajid Sandstone which crops out in southwestern Saudi Arabia has been mapped as a single lithologic unit with a Cambrian-Ordovician age. Seismic ties to the outcrop, recent fieldwork by Bureau de Recherches Geologiques et Mineres (BRGM) and Saudi Aramco' geologists and stratigraphic information obtained from a shallow 2260-foot test well (V-608) suggest that the Wajid Sandstone (as mapped in the outcrop) may be divided into five units and that the rocks range in age from Silurian and older to Permian. From oldest to youngest, the five units are the Saq and Qasim formations undivided (Cambrian-Ordovician age), the Zarqa and Sarah formations (Late Ordovician to Early Silurian age), the Qalibah Formation of Early Silurian age, rocks of Devonian to Middle Carboniferous age undivided, and the Unayzah Formation (Haushi Group) of late Carboniferous to Early Permian age. Except for the Qalibah Formation which is the source-rock of recently discovered oil in the Hawtah, Dilam, Raqhib, Nuayyim and Hazmiyah fields to the north, all of these Paleozoic sands have excellent reservoir potential in the subsurface.
It is proposed that the term Wajid Sandstone be dropped from usage and that the existing Paleozoic nomenclature discussed above and used by Saudi Aramco be applied to the Wajid Sandstone outcrop.
Programming System Development for Supervisory Control Systems
Authors: Zink Jerry L. 
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers Inc.

Abstract
Flexibility is the key word in selecting the general purpose digital computer for supervisory control systems. The economic objectives of supervisory control are dependent upon utilization of this flexibility in matching the changing conditions of the oilfield. The development of an excellent programming system is vital to utilization of this flexibility.
This paper discusses the steps Continental oil Company uses in developing a programming package for oil production control systems. package for oil production control systems. These steps include:
selecting a central processing unit, fixing the programming processing unit, fixing the programming responsibility, selecting a programming staff, training the programming staff, developing a programming environment, and establishing programming concepts.
Program systems development is dynamic rather than a static process. Therefore, it is likely that many of the ideas presented will be modified as further knowledge and development in the computer control field becomes available.

SELECTING A CENTRAL PROCESSING UNIT
After a feasibility study shows that a supervisory control system should be installed, several important decisions must be made which will affect the growth and operation of the system. The most important of these decisions involves selecting the equipment to be used as the central processing unit.
"Hardwired" or fixed logic units were predominant during the introduction of supervisory predominant during the introduction of supervisory control systems to the oilfield. Later, limited programming capability was added to these fixed programming capability was added to these fixed logic units by means of drum memory. Today the trend is toward the use of a general purpose digital computer as the central processor. The factors influencing this trend are summarized as follows:
The ability to program the logic of the digital computer offers increased flexibility over the "hardwired" unit. Detailed analysis of process variables needed in current systems requires the use of complex logic not available in "hardwired" central units.
Shallow Gas Blowout Kill Operations
Authors: Adams N. J. , Kuhlman L. G. 
Published: December 2007

ABSTRACT
Shallow gas blowouts, as a general class, are the most difficult type of blowout to kill. This paper discusses current industry myths about shallow gas, typical results from a shallow gas blowout that affect the kill operation, kill options and selection criteria, rig selection criteria, and well killing guidelines. The new kill technique of vertical intervention is discussed relative to shallow gas blowouts. Also, a new technique for using horizontal wells in combination with the reservoir flood technique for killing shallow gas, cratered blowouts is explained.
The Impact of Improved Technology on Potential Tight Gas Reserves in the San Juan Basin: A Case Study
Authors: Haas M. R. , Crist T. E. 
Published: December 2007

Abstract
This study evaluates the impact of technology on potential tight gas reserves in the context of current pipeline capacity and project economics. This case study of the Dakota formation is part of a larger analysis of tight sand formations in the San Juan basin, the findings of which are available in a separate report.1
This paper reports the result of a disaggregated appraisal of the remaining Dakota tight gas resource and estimates of gas in place, technical recovery and potential reserves. A location-specific resource database was constructed and typical well recoveries were modeled on a township-specific basis. Project costing and cash flow economics were analyzed to derive potential reserves for various technology specifications and wellhead prices. These data provide a foundation for operators and pipelines to more closely examine the Dakota for development in the near future.
Gas in place for the undeveloped tight portion of the Dakota was estimated at 11.1 Tcf. Potential recoverability with current technology is 4.3 Tcf. Potential reserve additions are 0.6 Tcf at $2.00/Mcf, 1.9 Tcf at $3.00/Mcf, and 3.2 Tcf at $5.00/Mcf. The availability of the Alternative Fuels Tax Credit for certain Dakota wells drilled in the next two years another two years could improve project economics by an equivalent of as much as &lt;body_st&gt;.88/Mcf at the wellhead.
As part of this study, depth, overburden and isopach maps were prepared and a resource database constructed. The database was analyzed using an integrated recovery and economics model for tight sands that has the capability to do rapid sensitivity analysis of geological, technology and economic assumptions. Although this study has identified the tight sands potential for various areas of the basin, more detailed geologic appraisal and reservoir engineering should be conducted before drilling.
Coalbed Methane Production Potential of the Rock Springs Formation, Great Divide Basin, Sweetwater County, Wyoming
Authors: Young G. B. C. , McElhiney J. E. , Dhir R. , Mavor M. J. , Anbouba I. K. A. 
Published: December 2007

ABSTRACT
Recent development of the Rock Springs Formation in Sweetwater County, Wyoming indicates coalbed methane production potential. Triton Oil and Gas Corp. drilled the #2 UPRC-1 well late in 1989 to test the potential of these coals. An analysis of the data collected indicates that gas content uncharacteristically decreases linearly with depth between 3,400 and 4,000 feet beneath the Triton property, with discontinuities in this relationship occurring both at shallower and deeper ranges in depth. A 25-year prediction of gas producibility for the well using the COMETPC 3-D reservoir simulator indicates approximately 1.0 BCF cumulative gas production or 61% of the gas-in-place for a 160 acre well spacing. These reserves are based only on 14.5 feet out of 36.5 feet of total coal to be completed in the #2 UPRC-1 well. This paper provides some of the first publically available information on commercial coalbed resources in this portion of the Great Divide Basin, part of the greater Green River Basin.
A Reservoir Simulation Investigation into the Interaction of In-Situ Stress, Pore Pressure, and Coal Rank on Coalbed Methane Exploration Strategy
Authors: Reeves S. R. , Decker A. D. 
Published: December 2007

Abstract
Coalbed methane exploration must evolve to adequately reflect a growing geologic and reservoir understanding in domestic and international coal basins. Currently accepted exploration strategies in the San Juan Basin of New Mexico and the Warrior Basin of Alabama are basin specific and remain unproven outside these traditional methane plays. Future development will require modified exploration strategies to locate commercial prospects in the more complex geologic settings of other less favorable domestic and overseas basins. Coalbed methane operators presently focus exploration efforts on locating areas of improved permeability, over-pressured hydrologie conditions, high methane storage capacity coals and a maximum ratio of gas desorption pressure to initial reservoir pressure. The effects of each of these reservoir properties and more importantly their interaction has not been thoroughly examined.
A reservoir simulation study was undertaken to investigate the effects of stress setting as it relates to permeability, pore pressure gradient and coal rank in terms of isotherm characteristics and gas content. A series of 162 well performance simulations were conducted evaluating the interaction of depth, coal permeability in high, normal and relaxed stress settings, gas contents for high, medium and low rank coals and finally, normal and abnormal hydrologie conditions. The results indicate that 1) there is an optimum target depth for a coal of a given rank under a specific stress setting, 2) the optimum producing depth increases with decreasing stress setting, 3) low rank coals exhibit superior production than higher rank coals under similar reservoir conditions and 4) the ratio of desorption pressure to initial reservoir pressure is of less significance than the absolute value of the desorption pressure. Based on these findings, fundamental inadequacies of existing exploration criteria require modification, particularly to the interaction of specific coal reservoir properties.
Analysis of Slug Test Data from Hydraulically Fractured Coalbed Methane Wells
Authors: Rushing J. A. , Blasingame T. A. , Poe B. D. , Brimhall R. M. , Lee W. J. 
Published: December 2007

ABSTRACT
This paper presents new type curves for analyzing slug tests in hydraulically fractured coal seams. The type curves were developed using a finite-conductivity, vertical fracture model and are presented in terms of three parameters – dimensionless wellbore storage coefficient, dimensionless fracture conductivity, and fracture-face skin. With these new curves, we may estimate the hydraulic fracture half-length, the formation permeability, and the fracture conductivity. We also present a procedure for using the new curves and illustrate the procedure with an example.
Using In-Situ Stress and Permeability Thickness Profiles to Design the Well Completion
Authors: Holditch S. A. , Whitehead W. S. , Rahim Z. 
Published: December 2007

ABSTRACT
Most completion engineers use two-dimensional fracture models to design hydraulic fracture treatments. These engineers also use two-dimensional reservoir models to analyze post-fracture production and pressure buildup data. Normally, a completion engineer will concentrate only upon a single zone and will often design a well completion based upon the properties of that zone as computed from log data, core data, drilling data, or other information about the interval.
Once the interval has been evaluated, the completion engineer will pick the location of the perforations based upon the location of the net pay zone. Estimates of porosity, water saturation, and net pay thickness are used to determine where to shoot the perforations and to estimate the value of fracture height that will be input into the two-dimensional fracture design model.
By using a two-dimensional fracture design model, the completion engineer is dictating the fracture height and the fracture shape. If the engineer uses the wrong fracture height, then the calculated values of fracture length and width will also be wrong. Most of the time, an engineer tends to underestimate fracture height and, thus, overestimate fracture length.
Effect of Injected Fracture Fluids and Operating Procedures on Ultimate Gas Recovery
Authors: Sherman J. B. , Holditch S. A. 
Published: December 2007

Abstract
In low permeability gas reservoirs, hydraulic fracturing is often necessary to stimulate gas recovery and provide economic gas flow rates. A hydraulic fracture is created by pumping large volumes of high viscosity fracturing fluid containing a granular propping agent into the formation. The well productivity is improved by creating a highly conductive flow path from the formation to the wellbore. Achieving and maintaining sufficient fracture conductivity is critical to the optimization of gas recovery from hydraulically fractured wells. The purpose of this research is to study how certain factors affect fracture fluid clean-up behavior, well productivity, and ultimate gas recovery from hydraulically fractured wells.
Several studies have been performed to investigate fracturing fluid clean-up behavior and well productivity. A few studies have determined how various parameters affect fracturing fluid clean-up,1–6 while other studies have focused on the factors that affect the productivity of hydraulically fractured wells.7–10 The previous work defined some of the problems associated with the clean-up behavior and well productivity. We have extended the previous work to identify the reservoir conditions that determine how productivity is affected by clean-up behavior.
The objectives of this paper are: (1) to investigate the factors that affect fracture fluid distribution around a fracture; (2) to determine which factors most affect fluid clean-up behavior after a fracture treatment; (3) to quantify the factors that affect well productivity after a hydraulic fracture treatment; and (4) to provide recommendations concerning how to produce a well after a hydraulic fracture treatment to optimize gas recovery. This research was performed as part of the Tight Gas Sands Research Program sponsored by the Gas Research Institute (GRI) in Chicago, Illinois.
Decline Curve Analysis for Variable Pressure Drop/Variable Flowrate Systems
Authors: Blasingame T. A. , McCray T. L. , Lee W. J. 
Published: December 2007

ABSTRACT
The motivation for the work described in this paper arose from a need to analyze production decline data where the flowing bottomhole pressure varies significantly. The variance of the bottomhole pressure with time excludes the use of the exponential decline model for conventional decline curve analysis (semilog plots and type curves). Using pressure normalized flow rate rather than flow rate usually does not remedy this problem. The method we present uses a rigorous superposition function to account for the variance of rate and pressure during production. This function is the constant rate analog for variable-rate flow during post-transient conditions and can be used to develop a constant pressure analog for the decline curve analysis of field data.
The constant pressure analog time function is computed from the constant rate function using the identity that cumulative production for both cases must be equal. Using the cumulative production identity, we solve recursively for the time function using trapezoidal rule integration and, as an alternative, finite difference formulae. We have also developed a constant pressure analog time relation which is rigorous for boundary dominated flow and serves as an accurate approximation for transient flow.
We apply these relations to analytical solutions for verification and then use the boundary dominated flow relation on simulated and field cases. These simulation cases include large and small step changes in bottomhole flowing pressures, and periodic shut-ins. Finally, we apply these relations to a gas well field case.