bluuebunny/crossref_metadata_2025 huggingface dataset:
Peninsular Malaysia Gas Producing System : Upstream Security of Supply Study
Authors: Othman Hasliza , Christensen T. G.
Published: December 2007

An increase of gas utilization in Peninsular Malaysia causes an expansion of upstream gas producing facilities. As the number of the facilities increases, it becomes important to predict the reliability of the integrated system to ensure sufficient delivery of gas to meet the consumer needs while maintaining economical investments. Due to the complexity of the system, a joint study between PETRONAS, Esso Production Malaysia Inc. and PETRONAS Carigali Sdn. Bhd. was conducted to analyze the gas supply system reliability and determine the overall system capability to make-up for production losses due to failures of equipment within the system.

The study was conducted in two phases. Phase 1 of the study involved the assessment of the existing facilities and also the facilities that are in advanced stage of development to determine the system availability. Phase 2 utilized the same concept as Phase 1, but models were created for long term development options to better define future design and sparing philosophies.

This paper describes how the upstream gas system model was setup using a statistical simulation software specifically designed to model process systems. The general layout of the offshore gas platforms and the onshore receiving facilities and the basis used in setting up the model are discussed briefly. Examples of results obtained for the existing system and the applications of model to help assess future competing development options will also be discussed.
Technology-Driven Infill Oil Development Planning of a Mature Offshore Area, Brunei Darussalam
Authors: Fah Yap Kong , Carter R. R. , Walton W. , Hupje R.
Published: December 2007

Maturing remaining undeveloped oil reserves into robust profitable development projects while aiming to achieve significant reduction in the unit technical costs are the key challenges facing the further development of mature oil fields in Brunei. Rising costs and flat oil prices have made conventional development uneconomic or marginal at best. The success of future development efforts relies heavily upon improving the key development drivers including well reserves, production rates and development costs. These are often challenging tasks, especially in Brunei Offshore Fields, where reservoirs are located in areas of significant stratigraphic and structural complexity. Development opportunities are also constrained by limited conductor slots from fixed platform locations.

This paper describes the current initiatives in BSP to mature the remaining undeveloped oil reserves in the shallow reservoirs of the Champion Field, Offshore Brunei, into robust profitable projects through a focussed approach of improving the key development drivers. We describe the application of state-of-the-art technology in 3D reservoir modelling to provide better infill development locations and improved production forecast estimates, together with the use of more innovative development options. The aim is to maximise well reserves and production rates, and minimise development costs. This will significantly improve the economics of subsequent development projects which would otherwise be uneconomic if the historical norm of conventional development would continue.
Peninsular Gas Utilisation Project: Planning And Challenges to Meet Customers Demand From the Perspective of a National Oil Company
Authors: Seong Chen Kah , Abdullah Mohamad bin
Published: December 2007

This paper presents the challenges faced by PETRONAS in ensuring a secure and sustainable gas supply to meet the market demand for the PGU project. Key to the success are good knowledge and understanding of gas demand trends, integrated long term gas fields development planning, and early identification of future gas supply challenges.

Gas demand projections and current observed trends, trends of existing gas development projects and environments surrounding future gas development are discussed. Technologies and strategies that are expected to have a positive impact on future developments are also discussed.

The information provided in the Paper supports the following observations and conclusions; (1) realistic gas demand forecast is essential to ensure that supply capacity matches the demand; (2) integrated long term gas fields development planning requires consideration of gas market, available delivery capacity, technical readiness of the field, available pipeline and processing capacity ullage to tie-in other fields, ability to provide security of gas supply to meet demand fluctuations, requirement to provide infrastructure for possible tie-in of future gas fields; (3) the challenges of future gas supply are to develop smaller gas fields, gas fields located in remote location, gas fields having high CO2 content and enhancing reliability of supply.
Cementing Practices - 1972
Authors: Johnson Robert M. , Garvin Thomas R.
Published: December 2007

This paper presents a review of experience for successful cementing in oil and gas wells. Recommendations and considerations for use of various cements, flushes, control additives and placement techniques are given for best results in placement techniques are given for best results in zone isolation and support of pipe in wells. Recommendations for control of difficulties with gas migration, mud contamination, high temperature retrogression, small annular clearances, and displacement of drilling fluids are described.

The purpose of this paper is to describe the latest advancements in oil and gas well cementing.

Introduction

As drilling operations become deeper and more costly, the significance of zonal isolation in cemented wells cannot be overemphasized. High temperature strength retrogression of cements and inefficient displacement of contaminants from small annular clearances has become more critical for economical exploration. Use of specially formulate cements, special control additives, and well planned programs for cementing have largely alleviated the programs for cementing have largely alleviated the basic problem of cementing failures, i. e., channeling.

With basic cements, additives are used that control filtrate loss, control retardation of hardening, provide desired hydrostatic column weight, and assist placement of permanent bonding materials to help prevent fluid migration and communication. Other additives stabilize hardened cement strength and maintain low permeability in cement even under extreme conditions of temperature and pressure associated with deep drilling. The problems of cementing in complex geometries and narrow annuli have been combated by perfecting techniques of slurry placement through rheological design, use of effective washes and flushes, and improving the mechanical aspects by using pipe movement with centralizers and scratchers. The delayed set technique for cementing has also been introduced to overcome some of these complications.

This paper describes these cements, additives and techniques as they are currently being used for successful cementing.
GideGard - The New Molded-On Epoxy Bit Protector Promises Longer Bearing Life
Authors: Moore Roy N.
Published: December 2007

Introduction

What is a Gide Gard? It is a new rock-bit protector that saves drilling money. The protector that saves drilling money. The development of this "molded on" epoxy rock-bit protector promises longer bearing life for the protector promises longer bearing life for the bit and offers maximum protection to the blow-out equipment, casing, liner and walls of the borehole.

Until the new rock-bit protector was developed, the bit had a poor chance of reaching the bottom of the hole without some impact damage to both the borehole and the bit bearing. A mute witness to this fact is the violent dance of the weight indicator hand as the unprotected bit is being pushed, gouged and bounced through the many formation seams. Although the new bit protector may soon become standard on all rock bits, the major breakthrough here is that progressive drilling people have recognized the fact that costly people have recognized the fact that costly hazards do exist in placing a rock bit on bottom.

HISTORY OF THE BIT CUTTER PROBLEM

For years, the driller demanded a rock-bit bearing that would withstand the unknown geology, higher drilling weights, faster rotary speeds, and the hostile environments of the hole. To meet this demand, the manufacturing engineers designed new rock bits with both seal bearings and friction bearings. Very little consideration was given to the bearings that may have been damaged while tripping the rock bit to bottom.

But the problem was real; the finest bit ever manufactured was being damaged going in the hole, and the most sophisticated instruments were unable to predict the minimum bearing life. A further study of many dull rock bits showed the bearings on one cutter to be worn two or more grading points more than the bearings on the other two cutters-and not always on the same cutter. To compensate for this, the drillers began to impose safety limits on the maximum depth and the maximum revolutions of a rock bit.

As more reliable bit data was accumulated, it became obvious that depth, condition of the hole, hardness of the formation seams, and the speed at which the bit was being lowered into the hole were the major causes of premature rock-bit failures. It also lent credence to an old rule of thumb, i.e., the revolutions of the bit on bottom are generally proportional to the "trip-in-hole" speed; or the more time used to go in the hole, the more drilling time on bottom; or a bit damaged going in the hole will turn fewer revolutions.
Four and One-Half Years - Discovery to Unitized Operation of the Major, Multi-Reservoir Bell Creek Field
Authors: Farnham Frank E. , Haddenhorst Fred A.
Published: December 2007

Unitization of the Bell Creek Field in Montana is believed to be unique in that a Working Interest owners Association was formed and dedicated to achieving that goal. Through this vehicle the seventy-eight participating owners were not only able to participating owners were not only able to expedite the unitization work, but collectively financed $444,100 of preunitization expenses. Bell Creek is also unique in that it is the first waterflood in the Rocky Mountain area to exclusively use turbine engines directly coupled to centrifugal pumps. Each of these units is rated at 1100 HP and will deliver 27,000 BPD at 1500 psi. Ultimate field injection will be approximately 120,000 BPD.

Introduction

Discovery of the Bell Creek field occurred in June, 1967. Unitization proceeding began with an operators meeting in January, 1968, but little progress was made until an association of all the working interest owners was formed in December, 1968. Under the auspices of this Association an Engineering and Geological Subcomittee began intensive studies which culminated in the delineation of some 26 individual productive sands and the formation of six secondary units. The first unit became effective April 1, 1970 and the last two units became effective January 1, 1972.

Initial oil-in-place for the entire field area is estimated to be 243 million STB. The ultimate primary recovery is estimated to be 48 million STB or 19.8%. Of the potential secondary recovery processes, potential secondary recovery processes, straight waterflooding yielded by far the best rate of return. The calculated additional recovery as a result of waterflooding is 44 million STB or an additional 18.1% of the initial oil-in-place.
Effects of Drainage Shape and Well Location on Stabilized Gas Deliverability Calculations
Authors: Rodgers John S. , Prasad Raj K.
Published: December 2007

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

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.

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

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

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

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.

P. 65
Determination of Volumetric Sweep Efficiency in Mature Waterfloods Using Production Data
Authors: Cobb W. M. , Marek F. J.
Published: December 2007

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

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

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

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.
Reservoir Management in the B-6/9, SVS-82, Lake Maracaibo, Venezuela - New Exploitation Policy for Maximizing Profit
Authors: de Carvajal G. , Banerjee S. , Carrizales R. , Garrido M. , Lozada T.
Published: December 2007

B-6/9, SVS-82 reservoir is located in Blocks IX and X in Maraven's concession area in Lake Maracaibo Basin in Western Venezuela. The field has been on production for more than 30 years and the recovery to date has been 45% of the OOIP (930 MMSTB). Its remaining reserves are confined between a gas front formed by the re-injection of the produced gas and a water front created by a strong aquifer in a relatively small area towards the top of a monoclinal structure. Though the reservoir is fairly well depleted, a prudent and comprehensive reservoir management program implemented during the past three years has substantially improved the production from this reservoir and consequently, the reserves have increased. This was accomplished by using new and existing technologies, such as, integrated reservoir characterization, 3-D Seismic, non-conventional simulation techniques, well workovers highly deviated wells and infill drilling. Prompt implementation of the exploitation policy has increased the reservoir production from 6 MSTB/D to 22 MSTB/D.

An integrated reservoir characterization study covering 3-D seismic, geology and geophysics, sedimentology, petrophysics and engineering has helped delineate the new reservoir limits and identified additional reserves and drilling prospects. A finely layered 3-D, 3-Phase reservoir simulation model was developed for a partial area of the field where most of the remaining reserves were confined between the advancing water and gas fronts. The Enumeration technique of reservoir initialization allowed a quick start of the forecast cases to investigate the productivity of the high angle wells and various combinations of infill drilling scenarios. The optimum number of infill wells — 20, was determined by economic factors.

Introduction

B-6/9, SVS-82 is one of Maraven's largest light oil reservoirs, located in blocks IX and X in Maracaibo Lake, Venezuela (Fig. 1). Production started in 1965 and in 1974, a gas injection project was initiated mainly for the purposes for storage and conservation. After 31 years of production, 45% of the OOIP (417 MMSTB) has been produced. The drainage strategy implemented in this reservoir has caused the remaining reserves (80 MMSTB) to be confined updip between the advancing gas and water fronts in a relatively small area towards the northern part of the reservoir.

In 1993, the Ministry of Energy and Mines (M.E.M) restricted the production from the reservoir. High GOR wells >2500 SCF/B) had to be closed thereby reducing the reservoir oil rate to 6 MSTB/D. Production of high volumes of gas did not conform with the current reservoir drainage strategy (gas injection). Since it would be difficult to achieve the expected ultimate recovery for this reservoir under these conditions, a complete re-engineering of the project was initiated. Figure 2 shows a schematic of the reservoir management program that has been underway since 1993.
An Analysis Of Volumetric Balance Equation For Calculation Of Oil-In-Place And Water Influx
Authors: Tehrani D.H.
Published: December 2007

When fluids are withdrawn from a petroleum reservoir, the space left behind is filled partly by the expansion of the remaining fluids and rock and partly by the influx of water from a contiguous aquifer, if it exists. The Volumetric Balance Equation (VBE) is an expression Of this same statement. Its simplified form is:

Z = Ax + BY (1)

where;

Z = Total Fluid Withdrawals in MMRB

A = Original Active Oil-in-Place in MMRB

X = Unit Expansion

B = Water Influx Constant

Y = Water Influx Function

When sufficient historical data on X and Z are available, various functions for Y can be tried, and by the technique of least squares a set of values can be calculated for A and B.

It has been convenient to write the equation in the following form:

Z/X = A + B (Y/X) (5)

The advantage of this form is that firstly, it has only two variables, and least square calculations are easier for it; and secondly, the values of Y/X and Z/X can be graphically plotted, so that a linear trend can be visually examined. The disadvantage is that the equation has a low resolving power, and can produce erroneous answers. Nevertheless, in a literature survey carried out it was found that most authors used this form of Eq(5).
Application of Radioisotopes to Sub-Surface Surveys
Authors: Alberts A.A. , Cocanower R.D. , Bundrant C.O.
Published: December 2007

Recent advances in the technology of the use of radioisotopes has enabled the development of new techniques for oil and gas well surveys. Almost without limit, these surveys can be designed to answer questions regarding down-the-hole well conditions. They have been found to be reliable and relatively inexpensive. Early experiments used radium. Its use is objectionable because of its long half life. As other isotopes became available, this objection was overcome, so that today radioisotopes are revealing accurate subsurface information — the key to maximum production.

Application of the radiotracer technique requires the running of a reference log of the formation prior to addition of the radioactive material; the adding of the radioactive material to a fluid and pumping it into the well through perforations or into the open hole; the plating out, or filter cake build-up, of the radiotracer on the formation; and, subsequently, running several logs to determine the location of the tracer.

By comparison of these several logs, each to the other and to the base log, an interpretation can be made. It is possible, therefore, to locate permeable zones, to detect faulty cement at the casing shoe, to locate fractured zones, to locate communication between perforations, to assure correct location of a blocking agent, and to locate the cement top.

Operational hazards in handling radioactive materials cannot be minimized. However, they can be readily controlled, with little danger to personnel or of contamination of equipment, by the use of Atomic Energy Commission approved procedures.

This paper describes a few of the many possible applications of the plating-out technique in an effort to illustrate the potentiality of this new tool.

The isotope used in this work was received on allocation from the United States Atomic Energy Commission.

Introduction

Radioactive isotopes are being increasingly accepted as the key to accurate sub-surface information — the key to maximum oil and gas production. All of us are aware that the rate of flow of oil into the well-bore depends to a great extent upon the permeability of the producing formation. When these voids become plugged, oil production falls off. By a properly designed treatment, production may be restored.
Correlations for Design of Gas Transmission Lines
Authors: Walton Thomas A.
Published: December 2007

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 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 who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

When simulating a physical process, an engineer or a mathematician process, an engineer or a mathematician may choose to ignore some of the many influencing factors. In most cases, these factors are ignored because their effects are negligible. In some cases they are ignored because it makes the problem easier to solve. In the case of the general flow equation for steady state flow in pipelines, the flowing temperature pipelines, the flowing temperature has fallen victim to both of these reasons. Temperature effects are assumed to have little effect on pressure drop and even some of the pressure drop and even some of the more advanced simulations assume isothermal flow.

The general flow equation may be written in the form:

(1)

(2)

(3)

Ignoring elevations, this may be written:

(4)

(5)

However,

(6)
Temperature Logging In Injection Wells
Authors: Witterholt E.J. , Tixier M.R.
Published: December 2007

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 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 who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

To further the scientific aspect of temperature logging procedures and interpretation methods, theoretical models describing the exchange of heat between injection fluid, borehole, surrounding formation, and injection zone have been used to study; the borehole-fluid temperature during injection, as determined by rate, depth, and duration of injection, the temperature along the axis of the cylindrical system as it recovers under shut-in conditions from the disturbance due to injection, and the establishment of the formation-temperature disturbance due to injection of fluid. Comprehension of the heat-exchange phenomena involved has been stressed, rather than detailed matching of specific logs. In general, it was sought to establish what information a temperature survey could reasonably be expected to yield under "ideal" and actual field conditions. The results provide specific information concerning: - a criterion for running an injection temperature survey as a source of flow-rate data, - the effects of vertical heat exchange on temperature distribution during injection and shut-in, - the relation between time of shut-in and ability to discern the radial extent of the formation-temperature anomaly, and - the relation between rate and duration of injection and the radial extent of the formation anomaly. A principal conclusion from this study is that a temperature survey alone should not always be expected to yield volumetric flow information. Rather, a combination of temperature and flowmeter or tracer surveys should be conducted. Further, when injection has been going on for a considerable length of time, heat exchange within the formation can cause an anomaly of greater vertical extent than the injection zone itself.

P. 1
Performance History on Use of Biopolymer in Springer Sand Waterflood in Southern Oklahoma
Authors: Perry Boyce
Published: December 2007

An area within the North Alma Penn Unit, operated by Samedan Oil Corporation, has been selected to evaluate the effects of injecting a biopolymer at various concentrations into the Sims Sands reservoirs beginning during the early stages of waterflooding. The polymer "slug", sized equivalent to fifteen polymer "slug", sized equivalent to fifteen percent (15%) of the effective pore volume based percent (15%) of the effective pore volume based on a concentration of 250 parts per million (ppm), was started after thirty-one percent (31%) of the reservoir voidage had been filled with straight brine. Approximately thirty-nine percent (30%) of the polymer poundage has percent (30%) of the polymer poundage has been injected at a concentration of 304 ppm and has caused no apparent damage to the reservoirs. Five (5) of nine (9) producing wells have responded to water injection, and three (3) of these have shown a recent reduction in water production. Further injection will be required to fully determine the total effectiveness of the polymer, but there are early indications that the polymer is influencing the water cut in some wells.

Introduction

The North Alma Penn Unit is located approximately three (3) miles northeast of the townsite of Velma, Oklahoma in Stephens County. The Unit was formed in February, 1970 for the purpose of waterflooding three (3) Deese Sands and three (3) Springer Sands. Water injection was begun in November, 1970, into the lower Deese Sand (Pickens) and the Springer Sands (First, Second and Third Sims); injection into the upper Deese Sands is to be phased in as the in-line Sims producing wells phased in as the in-line Sims producing wells water out. For purposes of this paper, discussion will be limited to the Sims Sands.

The Sims Sands comprise approximately seventy-six percent (76%) of the total acre-feet of the net oil volume. Major faults separate each Sims reservoir into four (4) distinct fault blocks, and the northernmost fault isolates the area herein referred to as the "North Fault Block". It is within the North Fault Block where the injection of biopolymer fluid was begun in August, 1971, and is still in progress.

Selection of the North Fault Block for polymer injection was based on the following: polymer injection was based on the following:

- Uniformity of zones

- Complete closure of reservoirs with aquifers controlling three

- sides and a major fault on the southside.