bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Drainage Shape and Well Location on Stabilized Gas Deliverability Calculations
Authors: Rodgers John S. , Prasad Raj K. 
Published: December 2007

Abstract
Most of the published analytical studies on stabilized gas deliverability predictions are based on radial flow and a symmetric well location. This approximation gives erroneous results for lenticular drainage shapes or ones with the well located asymmetrically. The range of error expected from radial and symmetrical assumptions is investigated in this study with analytical solutions of a theoretical backpressure shift factor as a function of dimensionless time for various rectangular drainage shapes and well locations. For the theoretical reservoir studied, these solutions show that serious error is possible in determining stabilized deliverability from the assumption of a symmetric well location in a square drainage shape.
Deliverability projections incorporating the backpressure shift factor are generated for two theoretical cases. Case I for a well in the center of a square-shaped reservoir demonstrated stabilization in six months Whereas stabilization occurred in four years for Case II, an 8 × 1 rectangular reservoir with the well located at an extreme end. All other data affecting hydrocarbon pore volume and petrophysical properties of these cases were held constant. When the theoretical cases are produced at capacity, 69 percent of the total gas-in-place is recovered in Case I, compared to 47.4 percent in Case II, during the first Eve years of production. A technique for calculating a backpressure shift factor as a function of time for a given drainage shape is presented in the paper.
We conclude that reservoir geometry and well location should be taken into account for a realistic deliverability prediction.
Worldwide Occurrence of Abnormal Pressures, Part II
Authors: Rehm Bill 
Published: December 2007

Abstract
Following the general discussion of The Worldwide Occurrence of Abnormal Pressures Part I, Part II discusses some specific type Part I, Part II discusses some specific type examples in the United States, the North Sea, Africa and South East Asia.

Introduction
The following examples are selected as the general type example for the area under discussion. In each case the general trend of the pore pressure profile is plotted versus depth. pore pressure profile is plotted versus depth. Naturally, since each area is covered in a very general manner the type example is only a general example. When drilling, variations in the depositional pattern and in the position in a basin may cause an entirely different pressure profile. So these profiles are not to be profile. So these profiles are not to be considered as a drilling guide but rather as a general description of the conditions that have already been found in these areas.
In all of the examples given the general mechanism is compression of the shales with the formation of a cap structure. As a guide, the cap structure and the general lithology of the area is indicated in the text.
Abnormal High Pressure and Environment of Deposition
Authors: Martin Gene B. 
Published: December 2007

This paper was prepared for the Abnormal Subsurface Pressure Symposium of the Society of Petroleum Engineers of AIME, to be held in Baton Route, La., May 15–16, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
An apparent relationship of the environment of deposition to the occurrence of abnormal high-fluid pressures in a sand-shale sequence of the subsurface South Texas Oligocene is established. The abnormal high pressures are generally encountered in the "downdip" facies, which consists of deltaic sediments of alternating inner neritic (includes brackish and nearshore marine) and middle neritic (shallow marine) depositional environments.
There is an abrupt change in the environment of deposition that seems to coincide with the top of the abnormal high-pressure zone.
This new approach to predicting abnormal high-pressured formations can be used at the well site.
The key to a better understanding of the problems and the solution to these problems associated with abnormal high-fluid pressures may be found in an understanding of the depositional environments and history of the sedimentary basin. In order to accomplish this, there may be a need for more workers to examine surface and subsurface rock samples.

Introduction
Many workers have presented conclusions on abnormal high-fluid pressures encountered in boreholes throughout the world. Probably the Gulf Coast region of the U.S. is better known because of the numerous boreholes and the documentation available.
Many giant hydrocarbon accumulations are produced from normal pressured reservoirs, and probably the majority of fields are in this classification. However, giant accumulations have been discovered in abnormal high-pressured formations also.
Some questions that will be reviewed in this report are the following.Why is it that abnormal high pressures are encountered by the drill bit in some bore-holes and not in others when drilled to the depth in the same region?Are there any attributes of depositional conditions that are always associated with this phenomenon?How can we better predict the occurrence of abnormal high pressures within a petroleum basin?
Cased-Hole C/O Logs Replace Open-Hole Logging in Alberta's Heavy Oil Sands
Authors: Wyatt D.F. , Storozhenko K.K. 
Published: December 2007

Abstract
This paper presents a special case for replacement of open-hole logs by modem cased-hole carbon/oxygen (C/O) logs. The latest generation of C/O logs provide more lithology, porosity, and fluid type data than previous versions. Recent work has developed a body of knowledge and confidence in this new technology, and it is now considered feasible to use carbon/oxygen logging for open-hole log replacement in some field development scenarios.
The heavy oil sands in Alberta, Canada are prime candidates for C/O logging. These reservoirs have fresh waters, moderate to high porosity, simple sandstone lithology and heavy, viscous oil with low invasion. This paper demonstrates the use of C/O logs in an in-fill development project with well-known geologic structure and lithology, where the elimination of open-hole logs is a low risk, cost saving option.

Introduction
In the case history presented here, C/O logs run after several wells had been drilled and cased were used for formation evaluation, instead of the standard open-hole logs. This procedure reduced the formation evaluation costs 50% by eliminating the rig time used during openhole logging and for hole clean-up before and after the open-hole logging. Interpretations derived from the C/O log data were compared with open-hole evaluations of the wells in this study. The comparison shows that when properly applied in this simple lithology, cased-hole C/O logs provided complete formation evaluation with quality comparable to interpretations from open-hole data, with reduced operator cost and risk. In more complex lithologies or in the presence of mixed pore fluids, additional cased-hole measurements may be required for equivalent results.

Carbon/Oxygen Logging Technology
Carbon/oxygen (C/O) logging tools are cased-hole pulsed neutron devices that use induced gamma spectroscopy to determine oil saturation in reservoirs with low or unknown water salinity. Additionally, elemental analysis of the measured spectra can be used to determine lithology.
Early generation C/O logs suffered from poor repeatability and accuracy, and required stationary measurements to obtain even marginally acceptable data. A new generation C/O tool, the Pulsed Spectral Gamma (PSG) employs modem detector technology and improved data processing methods to obtain much more precise data and does not require stationary log measurements. The bismuth germanate (BGO) detector of the PSG tool has a superior sensitivity to high-energy gamma rays and is largely responsible for the dramatic increase in statistical performance of the PSG tool over earlier C/O devices. This improved sensitivity has increased the dynamic range of the C/O measurement from approximately 10% in older generation tools to 22% in the PSG (30% porosity, 10" borehole).
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Application of a General-Purpose Network Optimizer to Oil and Gas Production
Authors: Barua Santanu , Probst Alice 
Published: December 2007

Abstract
A general purpose non-linear Sequential Quadratic Program (SQP) based network optimizer such as NETOPT can be used to solve a wide range of optimization problems in the Oil and Gas production industry. Optimization can be used as a strategic field planning or design tool to maximize revenue or profit from a field or minimize cost. In addition it is applicable in the field on a periodic basis as a operations tool to determine optimum control settings for changing field conditions. Optimization may be also used to determine control strategies to meet production targets.
This paper discusses some of the typical problems where SQP based optimization can be readily applied to significantly reduce costs, boost production or profitability and make marginal projects viable. Specific application examples are briefly discussed to illustrate the use of a general purpose optimizer and to demonstrate the benefits that can be realized by applying such technology.

Introduction
Networks: Figure 1 illustrates a typical network. A network consists of points called nodes which are connected by node connecting elements called links. A link is made up of one or more pressure and/or temperature change device in series. A device may be a reservoir 'PR' completion, tubing, pipe, compressor pump, cooler, heater and other oil field equipment. A general network solver should have the ability to solve for any network structure and boundary condition. For e.g. the network may be a tree network or a complex looped network.
Nodes may be sources, sinks or junctions. The source and sink nodes are also called boundary nodes. To set up the network equations correctly, either pressure (P) or flow (Q) must be specified (known variable) at the boundary nodes. The network simulator solves the network equations for the unknown node pressure (and temperature) or flow and unknown link flows in the network.
The Network Optimization Problem: The optimizer adjusts the network decision variables such that the objective function is maximized or minimized while simultaneously satisfying the user defined constraints and the network equations.
The network optimization problem may be mathematically expressed as
x represents the network variables.
and y represents the unknowns of the network problem.
From the point of view of computer implementation there are two classes of variables in the optimization problem:The primitive or internal network variables andThe user defined external variables which are functions of the internal variables.
The external variable definition allows the user to define any algebraic function for F or Ci.
The non-linear constraint function Ci may be defined as a external variable.
N(y) are the network equations which are in general non-linear. P. 943^
Keys to Increasing Production Via Air Injection in Gulf Coast Light Oil Reservoirs
Authors: Gillham T.H. , Cerveny B.W. , Turek E.A. , Yannimaras D.V. 
Published: December 2007

Abstract
Following the long-term commercial success of air injection as a secondary light oil recovery process in the Williston Basin (documented in SPE 27792, 28733, & 35393), Amoco, with the support of the U.S. Department of Energy, is piloting the use of air injection for tertiary light oil recovery at West Hackberry Field in Southwestern Louisiana.
Air injection is ongoing at West Hackberry under the following two operating conditions:In a watered out oil reservoir, air is injected to generate incremental oil recovery through the Double Displacement Process (DDP, SPE 28603). DDP is the gas displacement of a water invaded oil column to recover additional oil through gravity drainage. West Hackberry possesses steeply dipping high permeability light oil reservoirs that exhibit water drive recoveries of 50%-60% of the OOIP versus gravity drainage recoveries of 90% of the OOIP. Although insufficient air has been injected to see production response, reservoir pressure has increased by 500 psi and air injection is continuing.In a low pressure reservoir with a gas cap and a thin oil rim, air is injected into the gas cap to push the oil rim to downstructure wells, to repressure the reservoir, and to gain the improved recovery benefit derived from DDP. As of May of 1997, the first two low pressure reservoirs to undergo air injection have increased production by a combined total of 150 BOPD (or 60%) above the normal decline. To build upon these results, air injection will be extended to similar reservoirs in the field.
Key project aspects discussed in detail include:valuable field experience gained from injection and production operations,the use of laboratory tests in the selection process for target reservoirs,the interpretation of laboratory results obtained from the combustion tube and the accelerating rate calorimeter, andthe numerical reservoir simulation employed to forecast tertiary oil bank development and movement, recovery profiles, and tie-in experimental and field data.
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Determination of Volumetric Sweep Efficiency in Mature Waterfloods Using Production Data
Authors: Cobb W. M. , Marek F. J. 
Published: December 2007

Abstract
Calculation of volumetric sweep efficiency in a mature water-flood is important. It provides an indication of the fraction of the reservoir which has been swept or not swept by the injected water. Additional oil recovery potential exists in the unswept portion of the reservoir. In most waterflood analyses, volumetric sweep calculations are computed using estimates of net injected water volumes. In many reservoirs, net injection volumes cannot be computed due to poor injection records or the loss of injection water out of zone.
This paper describes a technique for computing volumetric sweep efficiency using only oil production data. The method can easily be adapted for analysis in a computer spreadsheet or using simple graphical procedures. The method is based upon volumetric material balance and standard waterflood principles. It can be applied to those oil reservoirs possessing a free gas saturation at the start of injection or when no free gas is present. The procedure, however, is only valid after free gas fillup, and has broad application in many mature waterfloods.
The computed volumetric sweep can be coupled with routine production decline curve analysis to estimate ultimate volumetric sweep under current operations. The technique can be used to provide insight to the upside oil recovery potential under alternate injection schemes. Results of the analysis are dependent upon floodable pore volume, oil saturation at the start of the waterflood, connate water saturation, and average water saturation in the water swept portion of the reservoir. The procedure can be applied to both regular and irregular patterns.
How to Predict Formation Pressures of Cretaceous-Jurassic Age Sediments - Mississippi
Authors: Matthews W.R. , McClendon R.T. , Soucek C.R. 
Published: December 2007

Abstract
Recent investigations of the successful Cretaceous-Jurassic trend from northwest Florida into northeast Texas have identified certain high-pressure formations. These abnormal pressures have also been observed during actual drilling operations.
The authors, members of the Oilfield Products Division of Dresser Industries, Products Division of Dresser Industries, Inc., have studied these pressure zones in Mississippi and have developed a method of predicting them by interpreting lithologic predicting them by interpreting lithologic values from conductivity and interval transit time logs. The procedure and the interpretation and correction of terms are described in the paper.
Once a proper interpretation is established and plotted, formation pore pressures can be determined by formula or direct overlay. From these values, formation fracture gradients are obtained.
The relationship of formation pressure, fracture gradient and annular friction loss can be a valuable tool in setting up an economical, accurate and safe casing program for a well. Accurate interpretation of these values can also be the basis for well-control before, during and after drilling operations.

Introduction
The purpose of this article is to show how the relationship of shale lithologic properties indicated by logs can be properties indicated by logs can be correlated to indicate pressure within the earth's formations. Fig. 1 shows the limits of the area investigated by the authors, the Cretaceous-Jurassic trend extending from northwest Florida across Mississippi and Louisiana and into northeast Texas. Wells to 22,000 ft have been evaluated to date. At present, the accuracy limits when using resistivity or interval transit time methods appear to be plus or minus 1/2 lb/gal mud-weight equivalent. The method employed has been to plot the shale lithologic properties on semi-log graph paper, then to use either an overlay or an empirical graph solution to derive formation pressure.
Approximation of Pressures Ahead of the Bit by Analysis of the Exposed Pressure Seal
Authors: Herbert Rene , Harger C.G. , Pertuis J.B. 
Published: December 2007

Abstract
Although the petroleum industry has developed effective, and accurate techniques to analyze exposed formation pressure, drilling engineers continue to advance wells without knowing what pressures are ahead.
A technique has been developed by the D.A.T.A. (Data Acquisition and Technical Analysis) engineers of the Oilfield Products Division, Dresser Industries, Inc., to approximate pressures ahead of the bit. This paper describes that technique. paper describes that technique. The basis for the procedure is the theory chat stratigraphic pressures are encapsulated in pressure seals and that these pressures can be approximated by measurement of the seal. Such measurements are the drillability and conductivity of the seal.
Certain limitations presently exist in this technique, but field test results prove it to be an economical and effective tool for the drilling engineer to determine the course of a well.

Introduction
The petroleum industry has used numerous techniques to evaluate wireline logs and drilling equations for analyzing formation pressures. These techniques have been pressures. These techniques have been reasonably successful and have saved the industry time and money because of more efficient, economical drilling operations.
Methods and Evaluation of Explosive Fracturing in Oil Shale
Authors: Miller J.S. , Nicholls H.R. 
Published: December 2007

Abstract
The USBM developed methods for fragmenting oil shale formations with chemical explosives to prepare oil shale for in-situ retorting and to prepare oil shale for in-situ retorting and to evaluate the extent of fragmentation by various methods.
A combination of three methods of explosive fracturing was used:
(1) the displacement and detonation of a liquid chemical explosive in a natural fracture system,
(2) the use of 60 percent dynamite to relieve stress conditions of percent dynamite to relieve stress conditions of the rock around the wellbore and
(3) the use of pelletized TNT in a series of wellbore shots to pelletized TNT in a series of wellbore shots to fragment the oil shale.
An attempt was made to seal or grout around the fragmented oil shale by drilling 67 holes and displacing approximately 200 bbl of neat cement in the fracture system to aid in evaluating the fragmented zone.
Seven methods were used to evaluate the fragmented zone. The primary evaluation method was the recording of seismic waves to delineate the fragmented zone with results based on arrival time, amplitude and record quality. The data from the seismic measurements indicated the extensively fragmented zone was approximately 95 ft in diameter and 70 ft thick.
Results of the remaining methods of evaluating fractures-including airflow tests, coring of the expected fragmented zone, elevation measurements to indicate overburden crowning, and surveys with high-speed camera, impression-packer, and down-hole camera-agreed with and supported the data from seismic measurements.
Further field application of explosive fracturing and evaluation methods is needed to determine an effectively fragmented zone of oil shale for efficient in-situ retorting.

Introduction
The potential benefits from the development and application of explosives to prepare underground mineral and energy resources for extraction are attracting the serious attention of many engineers and scientists in government and industry. Current efforts are toward improving the fluid flow capacity of oil shale and very tight petroleum reservoirs. The purpose of explosive fracturing research in oil shale is to develop a method that will create sufficient explosive fragmentation and permeability for in-situ retorting.