bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Review of Steam Soak Operations in California
Authors: Burns James 
Published: December 2007

Thermal stimulation of oil producing wells by cyclic steam injection accounts for over 13 percent of the current oil production in California. Here is a description of some of the more important steam soak operations currently being conducted in 29 California oil fields through June, 1967.

Introduction
The tremendous upsurge in thermal stimulation of heavy oil producing wells by steam soak operations in recent years has reversed the 9-year decline trend of the total oil production rate in California. By the end of June, 1968, some 14,000 wells were actively involved in steam soak operations and over 139,000 B/D of additional oil were being credited to this thermal stimulation process. The total state production has increased from 795,238 B/D in Feb., 1962, production has increased from 795,238 B/D in Feb., 1962, to 1,026,000 B/D in June, 1968.
The substantial increase in oil production in turn created a widespread search for projects that could benefit from steam soak operations. This review was conducted to determine those areas in the state where steam soak operations were being successfully applied, and to recognize, if possible, which type of heavy oil reservoir had responded most favorably to this stimulation method. It was hoped that the results of the review would provide some practical guidelines to be used along with theoretical considerations in selecting future steam soak projects.

History
The following summarizes very briefly the active steam stimulation projects in the State of California from the inception of this process in 1958 until June, 1968.
1958 -- Shell Oil Co. began steam soak operations on a pilot basis in the Yorba Linda field. 1961 - The success of the Yorba Linda experiment was evident and Shell expanded their steam soak operations to include properties in the Coalinga field. During this year, Tidewater Oil Co. started hot water injection in the Kern River field. 1962 - Beiridge Oil Co. began steam soak and steam displacement operations in the South Beiridge field. 1963 --A total of 29 steam projects were in operation. 1964 - A total of 111 steam projects were in operation. 1965 -By December of this year, there were 284 steam projects in California, of which 17 were steam displacement and 267 were steam soak or "huff and puff" operations. 1966 -- By June of this year, there were a total of 339 steam projects in California, approximately 90 percent of which were cyclic steam soak operations. percent of which were cyclic steam soak operations.1967 - By June of this year, the number of projects had declined to 256. 1968 - By June of this year, the number had further declined to 242.
Table 1 summarizes these projects by fields as of July 1, 1967. All data are from C.C.O.P. records except for the number of generators in use. These figures were taken from miscellaneous published articles.
The estimated additional oil production from steam stimulation was about 120,000 B/D by the end of June, 1967. Approximately 408 generators were in use at this time, so that the additional production amounts to 295 B/D/generator.
JPT
P. 25
Fire Protection for Hydraulic Pumping Installations
Authors: Alford B.J. 
Published: December 2007

Abstract
A comprehensive study was conducted to determine the possible causes of fires in hydraulic pumping installations possible causes of fires in hydraulic pumping installations and to devise a system that would reduce fire hazards to an economic minimum. The study confirmed that the operating temperature of gas engines is sufficient to ignite a power oil leak spraying on the engine.
The system devised for reducing fires uses a shroud for deflecting leaking oil away from the gas engine, detectors to shut down the system in the event of a leak and piping designed to decrease the possibility of leaks. The system has been applied in the Rocky Mountain area at a cost of approximately $700 per power oil pump. The report gives the reasons for selecting this system and evaluates some of the steps taken.

Introduction
On June 15, 1966, at the Shell Oil Co. Rocky Mountain Div.'s Cabin Creek, Section 8, Hydraulic Pumping Installation, a fire resulted in equipment damages of $86,000 plus the value of deferred production. Two other fires had occurred at similar installations. As a result, a comprehensive study was made to determine the possible causes, and to develop a system to minimize these fire hazards.
New Procedure for Wellbore Flash Calculations
Authors: Litvak M. L. 
Published: December 2007

Summary
This paper describes a new wellbore flash procedure implemented in a compositional reservoir simulator. It is used for calculations of bottomhole pressure (BHP), surface rates, and fluid compositions of a production well from specified well boundary conditions. Coupled wellbore, well tubing, and surface separator models are considered. The procedure for the solution of the wellbore flash problems with specified production rate at stock-tank conditions and with specified tubing-head pressure is developed.
The new procedure has several advantageous features. Wellbore equations and separator flash equations are solved simultaneously. A new iterative technique is applied for the solution of phase-equilibrium and mass-conservation equations for each stage of a separator battery. Material-balance conditions are satisfied exactly in each iteration. A new rigorous algorithm is developed for the calculation of BHP if tubing-head pressure is specified.
Phase-equilibrium computations in surface separator stages consume a large part of CPU time, required for some large compositional reservoir models (about 50%). In the new procedure, K values are calculated by minimizing Gibbs free energy, and mass-conservation equations are exactly solved in each iteration. This approach provides significant computational improvement (by a factor of four) over previous wellbore flash computations in compositional reservoir simulators with a Cray XMP-416.
Vertical Turbine Pumps for Waterflood Injection
Authors: Wykes Claude E. 
Published: December 2007

Abstract
Vertical diffusers pumps for the development of reasonably high pressures have been available in one form or another for many years. With the increasing importance of secondary recovery operations in petroleum production, vertical turbine pumps appear more and more production, vertical turbine pumps appear more and more frequently as the most efficient energizer for waterflood injection systems.
Even with adequate performance records standing behind it, this type of pump is still not widely understood. Its inherent advantages of flexibility, simplicity, low initial cost and minimal maintenance expense have yet to be fully exploited. Greater familiarity with the machine, together with a study of actual applications, will demonstrate that the design, correctly applied, can often result in certain advantages to the knowledgeable user.
Like almost any kind of machinery, the vertical turbine pump has its range of best operation, within which it pump has its range of best operation, within which it excels over other equipment and beyond which it may be misapplied. Comparison with other types of pumps illustrates relative performance within these limits.

Introduction
Having been trained to an analytical turn of mind, engineers normally could be assumed to understand and to apply the basic concept of machine efficiency. However, the term "efficiency" has been distorted in the pump business, occasionally beyond recognition, because of the widely divergent paths of machine development through unrelated branches of industry. The result is a noticeable tendency to apply different rules depending on the type of equipment to be evaluated.
The data in Fig. 1 came from a company well known in secondary recovery oil production and represent the operation of a waterflood injection pump station through a period in which equipment was changed from positive displacement (PD) machines to vertical turbine pumps. Note how the power cost per barrel of water pumped, a direct function of the machine efficiency, decreased sharply after the PD's were supplanted by the verticals at lower purchase cost and in far less space. Yet the plunger units purchase cost and in far less space. Yet the plunger units are rated at 95 percent efficiency in their industry while the vertical turbines operate at 83 percent in terms used by centrifugal pump manufacturers. In this paper we shall attempt to reconcile this seeming paradox and to offer a sound engineering basis for quantitative evaluation of efficiency ratings as well as general design and construction details.
Reservoir Simulation With a Control-Volume Finite-Element Method
Authors: Fung L. S.-K. , Hiebert A. D. , Nghiem L. X. 
Published: December 2007

SummaryThis paper describes a control-volume finite-element (CVFE) method incorporating linear triangular elements for the simulation of thermal multiphase flow in porous media. The technique adopts the usual finite-element shape functions to evaluate flow potentials at the control-volume boundaries and uses the conservation equations for each control volume. The main advantage of the CVFE method over the finite-difference method is in the representation of complex reservoir geometries. In addition, desirable features, such as local grid refinement for near-well resolution, can be achieved simply and consistently. The control-volume approach enforces local mass conservation and permits a direct physical interpretation of the resulting discrete equations. These are significant advantages over the classical Petrov-Galerkin or variational finite-element methods. The method was implemented in a general-purpose thermal simulator. Numerical examples compare the proposed method with five-point and nine-point finite-difference schemes in terms of grid-orientation effects and run time. The CVFE method was found to reduce grid-orientation effects significantly. At the same time, computational cost was much lower than for the nine-point scheme. The geometric flexibility of the method also is demonstrated.
Simulation of EOR Processes in Stochastically Generated Permeable Media
Authors: Waggoner J. R. , Castillo J. L. , Lake Larry W. 
Published: December 2007

Summary
This paper deals with the competition between effects during miscible displacements through heterogeneous permeability media. Displacements with an even front are dispersive, others are a type of bypassing: fingering, caused by an adverse mobility ratio, or channeling, caused by heterogeneity and autocorrelation. Under most flow circumstances, channeling is the predominant type.
3D Simulation of Viscous Fingering and WAG Schemes
Authors: Christie M. A. , Muggeridge A. H. , Barley J. J. 
Published: December 2007

Summary
Water-alternating-gas (WAG) injection has been suggested as a way to reduce viscous-fingering. This paper presents 3D simulations to assess the combined effects of gravity segregation in the vertical plane and areal viscous fingering for miscible displacements with substantial viscous fingering and for WAG injection. The simulations illustrate variations in recovery with WAG ratio and viscous-to-gravity ratio. A procedure to recalibrate the Todd and Longstaff parameter for WAG schemes in which buoyancy forces have little effect is described. Use of this recalibration provided excellent agreement with results from detailed simulation. Where gravity is important, recalibration of the parameter is required; examples of recalibration coarse-grid calculations are presented.
A New Double-Porosity Reservoir Model for Oil/Water Flow Problems
Authors: Dutra T. V. , Aziz Khalid 
Published: December 2007

Summary
This paper presents a model that takes into account the transient nature of the imbibition process and the effect of variation in fracture saturation. Gravity effect is included in the calculation of the matrix equilibrium water saturation. This simple method requires only one equation per block per component. This is attained by an analytical transfer function that depends only on the fracture variables and by the assumption of instantaneous pressure equilibrium. The transfer function assumes that capillary pressure is the only driving force of the process and eliminates the matrix saturation from the fracture flow equations. The assumption of instantaneous pressure equilibrium eliminates the matrix pressure. The resulting model has the same form as standard single-porosity models. Results of the new model are compared with those from published laboratory experiments, very fine-grid simulations of matrix/fracture transfer for a single matrix block, and simulation of field-scale water-injection problems by standard double-porosity models. These results demonstrate that the new model provides an economical and accurate means of predicting the performance of fractured reservoirs.
Well Cooling by Down-Ho Circulation of Water
Authors: Keller H.H. , Couch Earl J. 
Published: December 2007

Abstract
Damage to production wells subjected to the high temperatures associated with in-situ combustion projects has been a problem since the advent of projects has been a problem since the advent of this thermal recovery technique. Injection of water down the annulus of hot wells has been successfully utilized for cooling and prolonging the life of such wells.
A mathematical model that is suitable for predicting the effectiveness of cooling water in a predicting the effectiveness of cooling water in a particular application is developed. Typical results particular application is developed. Typical results for practical ranges of the various parameters involved are presented.

Introduction
In the normal course of in-situ combustion operations, highly damaging conditions develop in the production wells as the combustion zone approaches, and these wells are subjected to high temperatures (up to 1500F). The resulting well damage is recognized as one of the more serious operating problems unique to the in- situ combustion process. Even in operations where well completions process. Even in operations where well completions have been specially designed to cope with this problem, the question arises as to how this problem, the question arises as to how this destructively high temperature can be kept within tolerable limits. A simple and economical approach to this problem is to circulate cooling water downhole. This method has been used with some success in shallow reservoirs. At greater depths, however, the heat exchange with the overburden surrounding the well and between the fluids in the tubing and the annulus tends to equalize the temperatures of the two fluid streams so that the cooling capacity delivered to the bottom of the hole decreases with well depth. This method would provide no appreciable control over the bottom-hole temperature at great depths.
In order to delimit the condition under which cooling by water circulation is effective, the wellbore temperature must be related to the waterinlet rate and temperature; to the reservoir depth, production rate, and initial temperature; and to the production rate, and initial temperature; and to the combustion temperature at bottom-hole depth. A model that meets these requirements and that will offer an approach for developing engineering solutions to practical design and operating problems is described in this paper.
Corrosion-Resistant Tubulars for Prolonging Gravity-Water-Injection Well Life
Authors: Farooqui M. A. S. Z. , Holland Scott 
Published: December 2007

Summary
Failure resulting from corrosion in gravity-water-injection (GWI) wells is a major concern in the Abqaiq field, Saudi Arabia. This paper presents alternatives investigated to prolong the life of the wells, results of in-situ corrosion tests of 13% Cr steel alloy, and studies of the effect of coupling 13% Cr alloy with carbon steel.
A Simple Approximation to the Pseudoskin Factor Resulting From Restricted Entry
Authors: Vrbik Jan 
Published: December 2007

Summary
Several procedures for computing the pseudoskin factor have been reported in the past, but they are either insufficiently accurate or require the use of a computer to perform the actual evaluation. This paper derives a simple formula that can achieve an accuracy quite sufficient for any practical application by means of a few approximations and use of an ordinary calculator.
Evaluating Gas Content of Black Warrior Basin Coalbeds From Wireline Log Data
Authors: Colson J. L. 
Published: December 2007

Summary
Coalbeds have long been known to contain natural gas in varying amounts. To the mining industry, this is basically a hazard to be controlled and avoided where possible. To the petroleum industry, it is an exploitable resource that holds significant economic potential because of shallow drilling and the promise of long well life. The variability of coal as a gas reservoir raises the need for oil-and gas-well explorers to develop the capability of evaluating coalbed gas content to identify and produce coal gas plays.
Current petrophysical models for gas reservoir analysis in traditional clastic or carbonate environments are notably inadequate for evaluation of gas content in coalbeds. However, numerous physical models exist for coals throughout the country, primarily from the efforts of the mining industry. A theoretical model was chosen and used to establish a method for evaluating gas content of coalbeds in the Black Warrior basin of Alabama. Core data in the form of proximate analysis, ultimate analysis, and gas desorption measurements were used, along with wireline data, to build the models. Results of data analysis in wells with coals ranging from low-volatile bituminous to high-volatile B bituminous are compared with core gas desorption measurements to demonstrate the accuracy of the process.
The thin coals in the Black Warrior basin require high-resolution logging (especially neutron and density tools) to obtain acceptable results. Wireline computations on a prospective well can be obtained much sooner than core desorption measurements and can provide analyses in zones where samples were not recovered. Implementation of these techniques in conjunction with core measurements can help significantly in determining the economic viability of coalbed-methane prospects.
Reservoir Simulation Study of a Thermal Horizontal Well Pilot in the Cold Lake Oil Sands
Authors: Adegbesan K. O. 
Published: December 2007

Summary
A reliable model was developed for evaluating and guiding the performance of horizontal wells in thermal operations to recover heavy oil in Cold Lake, Alta., Canada. The horizontal well model was developed with measured field data from the first thermal horizontal well pilot (HWPI) of Imperial Oil Resources Ltd.
Why Scale Forms in the Oil Field and Methods To Predict It
Authors: Oddo J. E. , Tomson M. B. 
Published: December 2007

Summary
Predicting potential scaling problems can be difficult, and numerous saturation indices and computer algorithms have been developed to determine if, when, and where scaling will occur. The Langelier, Stiff-Davis, and the Oddo-Tomson saturation indices, all widely used in the oil field, are compared and contrasted relative to calcium carbonate scale. New saturation indices for barium, strontium, and calcium sulfate scale formation are introduced and discussed, along with an updated version of the Oddo-Tomson calcium carbonate index. An updated version of the CaCO3 saturation index is presented that includes correction terms for fugacity effects and changes in the solubility of CO2 in oil and gas wells as functions of temperature, pressure, water cut, and hydrocarbons present. The CaCO3 saturation index does not require a measured pH and can accommodate the presence of weak acids, such as H2S, and weak organic acids in the system. The sulfate scale prediction methods (for gypsum, hemihydrate, and anhydrite) are easy to use, reliable, and designed for field use by an operator who may be untrained in chemistry. The prediction methods can be applied to any production well where calcium carbonate, calcium sulfate, strontium sulfate, or barium sulfate scale occurs.
Field-Tested Model for Freeze Protection of Arctic Multiphase Pipelines
Authors: Eager Kelly 
Published: December 2007

Summary
Freeze protection of water-bearing pipelines is an essential part of Arctic operations. Methods used to protect pipelines at the Prudhoe Bay field are discussed, including the development of an algorithm to predict the cooling times of multiphase flowlines and a field-tested program used to verify performance of the algorithm.

Introduction
The Prudhoe Bay oil field, located about 250 miles north of the Arctic Circle, is exposed to average winter temperatures of -35 degree Fahrenheit and below. Protecting outdoor pipelines from freeze damage is an integral part of field operation. Depending on the size, service, and location of an individual flowline, one or more methods can be used to protect it from freeze damage.
The field is laid out with centralized drilling and separation facilities, similar to large offshore fields. Wells are drilled from centralized well pads, with 10 to 50 production and injection wells tied to a common manifold. Commingled flow from the wellpad manifolds is routed to one of six central separation centers where crude is stabilized for shipment to the Trans-Alaska pipeline system. Produced water and pipeline system. Produced water and seawater, gas-lift gas, and miscible injectant are treated at the central plants and shipped to the well pads in cross-country flowlines. Injection fluids are routed to individual injection wells from the well-pad manifold. Pipelines between the wells and well-pad Pipelines between the wells and well-pad manifolds are called "well lines," and pipelines between central facilities and pipelines between central facilities and well pads are called "flowlines."

Freeze Protection Methods
When a pipeline is scheduled to be taken out of flowing service, or a production upset occurs, a reaction time is calculated. The reaction time is defined as the time required for ice to begin to form in the line minus the time required to protect the line. For example, in a water line to be protected by pigging, the reaction time is the estimated pigging, the reaction time is the estimated freeze time at current conditions minus the time required to displace water from the line with a gas-driven pig. Consideration of reaction times ensures adequate actions will be taken before the onset of freezing. Various protection methods were developed and protection methods were developed and tested as the field was developed and new facilities were added.
Fluid Displacement Methods. Displacement is a common means of protecting lines and can be completed by several different methods. Displacement of well lines with a heated water/methanol solution is used for production-well lines that are not level. The production-well lines that are not level. The solution is pumped into the line at the manifold building and the producing fluids are displaced to the wellhead and about 2,000 ft downhole to protect the wellbore from permafrost. Methanol displacement is the most common means of protecting shutin multiphase production and injection-well water lines.
In-Situ Stress Profiling and Prediction of Hydraulic Fracture Azimuth for the West Texas Canyon Sands Formation
Authors: Miller W. K. , Peterson R. E. , Stevens J. E. , Lackey C. B. , Harrison C. W. 
Published: December 2007

Summary
This paper presents results of hydraulic fracture azimuth and in-situ stress measurements for two wells in the west Texas Canyon Sands formation. The paper gives information for designing infill drilling patterns and improving fracture treatment designs. Eight techniques were applied to measure fracture azimuth; the results from each are discussed. In-situ stress was measured in 12 intervals, and the results were used to calibrate long-spaced digital sonic logs. This paper also discusses the application of calibrated stress to fracture treatment design.