bluuebunny/crossref_metadata_2025 huggingface dataset:
East Leman Unit Water Influx Investigation
Authors: Jeffries-Harris M.J.
Published: December 2007

This paper was prepared for the Second Annual European Meeting of the Society of Petroleum Engineers of AIME, to be held in London, England, April 2–3, 1973. 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 publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A two dimensional, two phase vertical reservoir model was used to simulate bottom water influx into the East Leman Unit. The influence of well cluster drainage, well drainage area, aquifer extent, permeability level, horizontal-vertical permeability ratio, aquifer-gas zone permeability ratio, and production after breakthrough were production after breakthrough were investigated. The results indicate that water influx will not be a significant factor in future performance primarily because of extremely low water mobility associated with the reservoir rock.

Introduction

The Leman Field is a large dry gas reservoir located approximately 30 miles off the East Anglian coast. It was discovered in 1966 and produces from the Rotliegendes sandstone, an aeolian deposit of Permian age, the gas being trapped in a northwest-southeast elongated dome approximately eighteen miles long by eight miles wide. The top-of the producing formation varies from 5,900 to 6,750 feet subsea within the field area providing a gross pay thickness at the crest of the structure of up to 850 feet.

The Leman Field reservoir is underlain by bottom water almost everywhere, and the influence on both well and field performance requires evaluation. performance requires evaluation. Furthermore, the importance of the field, its location offshore, and the essential fulfillment of contract requirements necessitates accurate long range development planning. To achieve this objective for the heterogeneous reservoir rock reservoir simulation for performance prediction is highly desirable. performance prediction is highly desirable. A two phase, three dimensional simulation model would permit the best evaluation of aquifer influence. However these models require elaborate data input and are time-consuming and difficult to set up.
Theoretical, Laboratory and Performance Characteristics of a Seawater-Salt Base Mud System for the North Sea
Authors: Methven Norbert , Schumann Claus
Published: December 2007

This paper was prepared for the Second Annual European Meeting of the Society of Petroleum Engineers of AIME, to be held in London, England, April 2–3, 1973. 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 publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A drilling mud system has been developed and applied in the North Sea and its environs that has a pollution free composition, a seawater-salt base and other unique advantages.

The salt base includes use of magnesium chloride, potassium chloride and/or sodium chloride. In addition to the seawater-salt base, the mud system includes magnesium compounds and a blend of polymers. The formulation does not include clays or poisonous thinners. The included salts poisonous thinners. The included salts provide shale inhibition and minimize provide shale inhibition and minimize dissolution of subsurface salt formations. Also, the salt water reduces formation damage and the included colloids and polymers are acid soluble to assure maximum acid stimulation results where applicable.

This paper describes the general chemistry, the results of laboratory tests, and the field performance of this mud system. In addition, this paper provides similar information on an adaptation of this mud system that has been developed in the United States and applied in the Gulf of Mexico.

Introduction

Three prime considerations in drilling exploration and development wells are prevention of pollution, minimization of prevention of pollution, minimization of drilling cost and maximization of well productivity. Each of these can be significantly productivity. Each of these can be significantly affected by the drilling fluid.

Pollution Prevention Pollution Prevention Pollution can occur from drilling fluids and drilling operations through use of poisonous and/or unsightly materials in the poisonous and/or unsightly materials in the formulation that may find their way to the sea. Thus in designing a drilling fluid, it is most desirable to start with non-poisonous materials and materials that are compatible with the environment.
New Developments in Platform Production Safety Systems
Authors: Carman R. Jan , Curington Wayne
Published: December 2007

A review of new equipment developments for platform wellhead safety systems is presented with special emphasis on increased operating efficiency and improved safety. This equipment more effectively meets new requirements of stricter regulations and inspections by the various regulatory agencies, while still maintaining maximum production efficiency and minimum downtime. For example, a much-improved flowline pressure monitor and safety-valve shut-down system has been developed, which allows the operator to set his low and high pressure shutdown points rapidly and with a resolution and accuracy not obtainable with conventional equipment. This capability is especially valuable in high production gas fields, such as those found in some North Sea areas, where the difference in flowline pressure at normal flowrates and at broken-line flowrates is small.

High capacity hydraulic equipment used in blow-out preventer control systems is being utilized to control hydraulic downhole safety valves, which are replacing the velocity-operated check valves previously used. Equipment such as high capacity gas driven and electric driven piston pumps, large float type accumulators and sliding seal pilot valves, all pumps, large float type accumulators and sliding seal pilot valves, all well proven in the drilling industry, is being applied to downhole safety valve control. This increased hydraulic capacity allows the safety valves to be opened at much faster rates after a shut-down, thus reducing lost production time and safety valve seal wear. production time and safety valve seal wear. New developments in the areas of electrical control systems, new safety valve operator designs, safety valve operator fire caps and position sensing limit switches are also described.
Legal and Regulatory Aspects of Fieldwide Unitization of Petroleum Reservoirs Extending Across Jurisdictional Boundaries of Bordering States in the North Sea
Authors: Horigan James E.
Published: December 2007

This paper was prepared for the Second Annual European Meeting of the Society of Petroleum Engineers of AIME, to be held in London, England, April 2–3, 1973. 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 publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The discovery of commercial petroleum deposits straddling international sub-sea boundary lines in the North Sea has become a reality. Present bilateral agreements between States bordering on the North Sea anticipated the possible existence of such jurisdictionally divided deposits or structures and established in general terms a joint policy understanding for the making of future international agreements on exploitation. These agreements are examined, particularly with reference to differing legal particularly with reference to differing legal and regulatory requirements between the bordering States as pertain to their respective exploration and production licensing practices. Fieldwide unitisation of such deposits and structures, as a method of apportionment and cooperative exploitation, is recommended for the avoidance of physical and economic waste, for the protection of the interests of the States and their respective licensees, and to achieve the greatest ultimate recovery of petroleum resources. The various and differing petroleum resources. The various and differing licence and regulatory terms are considered with reference to a formal unitisation plan, and consideration is given to the need for a uniform policy between the bordering States with respect policy between the bordering States with respect to the conduct of operations and other matters.

TEXT

The boundary lines which serve to delimit geographically the sub-sea jurisdictions of the bordering States of the North Sea were established, for the most part, prior to the discoveries of commercial oil and gas deposits in the North Sea. Consequently, there was no predetermined certainty on the part of the Governments on how and in what manner nature itself might cooperate to confirm or deny the validity of the equitable principles on which the manmade political lines of subdivision were drawn and agreed.
Operating Experiences - Offshore Storage and Loading Facilities
Authors: Muller S.E. , Prince C.A.
Published: December 2007

This paper was prepared for the Second European Meeting of the Society of Petroleum Engineers of AIME, to be held in London, England, April 2–3, 1973. 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 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. 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.

The Company has been operating the following offshore installation for three years:

One 500,000 barrel storage tank.

Two 250,000 barrel floating storagevessels.

One SPM, capable of handling 200,000DWT tankers.

The installation was selected based on economics of a given design and an assumed weather condition, tanker schedule, and mechanical failure. Experience has shown the submerged storage to be superior mechanically as well as exhibiting good quality wateroil separation. Costs, both initial and operating, are presented to show the relative economic merits of each type of storage. The weather conditions for the past three years as well as tanker schedule will be compared to that which was predicted before operations were commenced.

There have been some revisions made to the original installation. These revisions have been dictated by experience and will be presented in this paper.

Introduction

Dubai Petroleum Company, a wholly-owned subsidiary of Continental Oil Company, and operator for a multinational group of companies of a concession offshore from Dubai, U.A.E., has been operating a fully offshore crude oil producing and export facility in the Fateh Field for three and a half years.

At the time of start-up, the totally offshore characteristic of this operation was unique in the petroleum industry. The most renowned component of this installation was the Khazzan Dubai No. 1, the first submerged crude storage vessel of its kind. Complementing this vessel were two floating storage vessels, Majmaa I and II, converted from the forebodies of ocean going tankers. Total storage volume was 1.1 MM barrels.
Structural Relations of Organic Corrosion Inhibitors and Scale Preventives as Applied to Oil Field Chemistry
Authors: Hansen Gerald D.
Published: December 2007

Semipolar molecules such as surfactants are extensively employed in the production of petroleum for the solution of problems of petroleum for the solution of problems of corrosion, scaling, emulsion formation, etc. This paper describes some fundamental relations which have been developed between the structure of surfactant molecules and their action as corrosion inhibitors and as scale preventives. Also given are laboratory methods for predicting when scaling, etc., may be expected due to incompatibility of oil-field brines with one another or with additives such as employed in polymer and micellar flooding. polymer and micellar flooding. Correlation of published data on certain polar materials based on sulfur, oxygen and polar materials based on sulfur, oxygen and nitrogen have shown that in a given homologous series, corrosion inhibition effectiveness increases with increasing number of carbon atoms in the alkyl chain(s) attached to the polar group which adsorbs onto the metal. The polar group which adsorbs onto the metal. The Langmuir Adsorption constant increases by a factor of ten for each additional four carbon atoms added to the molecule, whether the chains are straight or branched, for sulfuric acid used in the pickling of steel. There is no significant difference in corrosion inhibitor efficiency in this system among the homologous series of oxygen and nitrogen compounds such as amines, ketones, and aldehydes reported; however, sulfur compounds of a given carbon number appear to be about two orders of magnitude more effective than nitrogen or oxygen compounds of the same carbon number.

Studies carried out on polar materials used as corrosion inhibitors and/or as scale preventives in other systems such as simulated preventives in other systems such as simulated oil field brines, cooling waters, boiler feed-waters, have indicated that although the adsorption concepts developed for acid corrosion inhibitors are of importance, other factors are of equal or greater importance. The concept of rate control of a precipitating salt such as calcium carbonate is developed and data presented indicating that the effectiveness presented indicating that the effectiveness of rate control additives such as phosphonates and polymers is determined by the magnitude of the formation constant of the compound formed by the cation and the additive as compared to that of the cation and the precipitating anion.
Stimulation Of Low Permeability Gas Wells In The Rocky Mountain Area
Authors: Carney M.J. , Wieland D.R.
Published: December 2007

This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Casper, Wyoming, May 15–16, 1973. 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 publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor 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.

The shortage of natural gas, which has resulted in an increase in gas prices, has stimulated the interest in gas production. Law pressure, low permeability gas producing formations are presently being completed, which in the past were plugged or completely neglected.

The majority of these gas wells have to be stimulated for them to be economical. Because of the low formation pressures and/or low permeability, great care must be taken to choose the proper fluid when performing a stimulation treatment. Fluid imbibition, capillary forces, frac fluid impurities, formation composition are some of the more critical factors that have to be considered.

This paper discusses the approach taken to evaluate the different low permeability gas formations as to the type of frac or acid stimulation fluid to use, the new fluids developed specifically for this type of problem, and field stimulation results for the problem, and field stimulation results for the different fluids used.

Introduction

Increasing demand and resulting shortage of natural gas has renewed interest in the search for and production of this product. Many wells and reservoirs which have been marginal or non-commercial in the past can now be produced profitably. The reason for their marginal or non-commercial status in the past has been the inability to successfully stimulate them to provide flow rates which were adequate at existing prices. Increased prices have reduced flow rates required for profitable production, but stimulation is still necessary production, but stimulation is still necessary and the stimulation problems still exist.
A Physicochemical Approach to the Prevention of Balling of Gumbo Shales
Authors: Chesser B.G. , Perricone A.C.
Published: December 2007

Gumbo-type shales have presented a multitude of problems in many drilling areas of the world, including "balled" bits, collars and stabilizers, plugged flow lines, and shaker screens. These problems can result in decreased drilling rate, lost circulation, stuck pipe, logging difficulties, and, in general, increased well cost.

A study was made of the gumbo-type shales which exhibit plasticity and adhere to the drill string and other drilling equipment. This work revealed that the balling tendency of these shales could not be controlled effectively with conventional inhibiting electrolytes such as gypsum, lime, sodium chloride, potassium chloride, etc. Thus, the clay base exchange or cation fixation mechanisms have been only partially effective in preventing the drilling problems associated with gumbo.

This paper describes a physicochemical approach to preventing the balling and sticking together of the massive gumbo shales. This approach is based upon the interaction of water with silica and alumina surfaces. This interaction produces a difference in proton density between the bound water on the clay surface and the pore or interstitial water. The electrostatic forces created by the proton density difference causes adhesion of clay masses. The adhesion resulting from clay-water interaction is believed to be the dominant factor in the stickiness and balling tendencies of these shales.

An organo-aluminum complex has been synthesized, which strongly adsorbs onto a clay surface forming an organo-aluminum-clay complex. The formation of this complex decreases the interaction between the particle surface and water, thus greatly reducing the adherence factor.

A number of test wells have been drilled successfully using this physicochemical approach in various parts of the world. Data and drilling performance criteria are presented in this paper, and a comparison with previous wells drilled with other fluids is given.

INTRODUCTION

The finding of new petroleum reserves to meet the increasing demand for energy has pushed exploratory efforts towards the various continental shelves and deltaic regions of the world. The cost of finding these new resources and producing them has reached enormous proportions, as evidenced by the recent exploration activities in the North Sea.
Fluid Loss Additive Seriously Reduces Fracture Proppant Conductivity and Formation Permeability
Authors: Pye D. Stephen , Smith Warren A.
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. 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 request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Fracture proppant conductivity can be severely impaired by certain fluid loss additives. Laboratory tests show this reduction in conductivity is frequently more than 50 percent, which tends to nullify any effect of percent, which tends to nullify any effect of fracture extent beyond a few feet from the wellbore. oil soluble additives appear be a possible solution to this problem. Other possible solution to this problem. Other experiments indicate that formation permeability is severely reduced at high permeability is severely reduced at high differential pressures. This damage to permeability would seriously impair the permeability would seriously impair the productivity of any zone which was not productivity of any zone which was not fractured.

Introduction

Hydraulic fracturing is a widely used and accepted method for stimulating the production from wells. The techniques and production from wells. The techniques and procedures, however, are constantly changing, procedures, however, are constantly changing, particularly in the past few years. Justification particularly in the past few years. Justification for using a new technique is naturally based upon its capacity to increase the production improvement from the stimulation.

Of the multitude of variables which determine the effectiveness of a hydraulic fracturing operation, only a few are easily controlled—fracturing fluid properties (viscosity, fluid loss, etc), injection rate and type of proppant. These three parameters influence the fracture length and the fracture conductivity.

Frequently, these variables are extremely difficult to evaluate from field results since tests on a large number of similar wells would be required. While a few of the new procedures have been documented with field tests, most of the recent changes in technique or procedure have been recommended on the basis of analog, mathematical or laboratory models of the fracturing process.

Laboratory models were used in our investigation to study the effect that fracturing fluids, and more particularly fluid loss additives, have on productivity.
Transient Method Implemented Under Unsteady-State conditions For Low and Very Low Permeability Measurements on Cuttings
Authors: Marsala A.F. , Figoni A. , Brignoli M.
Published: December 2007

This paper reports a complete description of a device, a numerical method and of a new experimental procedure that allows direct measurements of low and very low permeability on cuttings (small fragments of rock, down to 1–2 mm in diameter).

The results show the determination of shale permeability even in the order of few nanodarcies. This technique is included in a complete package of standard' measurements on cuttings (sonic, rock strength, porosity) and in particular it extends the range of permeability measurements, technique already developed for reservoir cuttings and presented elsewhere. Thanks to this technique it is now possible to obtain, while drilling, a complete permeability log' of rock formation even for very low values.

Traditionally, permeability can be determined on cores by a steady state flow rate measurement. To measure a permeability from 0.1 mD to 1 nD (=10-9 darcies) the pulse decay technique can be used. This technique is a transient method and it is implemented under unsteady-state conditions.

In a rock saturated with fluid, diffusion of a pressure gradient is much faster than the steady state flow of fluid itself. The transient method is essentially a measurement of the pressure gradient diffusion and it is applicable even for very low permeable materials. The technique applied to cuttings is described in this paper.

Some limits are intrinsic in this technology: the measurement is feasible only if cuttings have at least few mm in diameters; no discrimination is possible from a cutting's measurement in order of directionality (horizontal or vertical permeability); only matrix permeability is revealed from this measurement as no fracture permeability is detectable from the sole measurement on cuttings.

A new experimental apparatus is developed to run the tests, even at the rig site. Field results are presented and discussed along with the numerical methods to calculate permeability values from unsteady-state tests in the transient method.

From a rock mechanics perspective one application of the permeability log while drilling in shale formations is the calibration of wellbore stability models. Permeability is one of the key parameters which governs pore fluids re-equilibrium while and after drilling and definitely affects the time related instabilities.

Using this technique in the laboratory, along with other measurements on cuttings representative of field situations, improves shale-fluid interactions evaluation, aiming at optimising mud selection.

P. 33
Stress Trajectories in the Neighbourhood of Fault Zones
Authors: Pourjavad M. , Bell J.S. , Bratli Rolf K.
Published: December 2007

Stress trajectories around faults have been simulated with a 3-D finite element model, based on 8-model brick elements in five layers. Preliminary simulations imply that stress trajectory deflections in the neighbourhood of fault zones can be expected if there is a large geomechanical contrast between the fault zone and the adjacent rocks and if far field stress anisotropy is small. On the other hand, if the horizontal stress anisotropy is large, significant stress deflections appear unlikely to occur near a fault. Within a softer' fault zone H will be aligned approximately parallel to the trend. Magnitudes of maximum and minimum stress are modelled for soft and hard fault simulations. Significant modifications in stress magnitudes developed in the vicinity of the fault zones.

P. 33
Borehole Breakouts in Berea Sandstone: Two Porosity-Dependent Distinct Shapes and Mechanisms of Formation
Authors: Haimson Bezalel C. , Song Insun
Published: December 2007

We conducted laboratory-drilling experiments in Berea sandstone blocks of two different porosities in which borehole breakouts were induced under several truly triaxial far-field stress conditions. We used a petrographic microscope to study thin sections of the drilled boreholes and observed the mechanism of failure that ultimately resulted in breakout formation. In lower porosity Berea sandstone (17%) we identified a breakout failure mechanism that is similar in its final V' shape to that observed in granite and limestone, and occurring along the ah spring line. This shape results from successive spalling of slabs initiated by dilatant intragranular microcracking subparallel to a~ direction, The cracks extend intergranularly due to the much lower toughness of the rock matrix, and reach the borehole wall along tortuous diagonal paths, forming a wide-angle V'- shaped notch. A dramatically different failure mechanism was observed in the higher porosity sandstone (22.5%), a more weakly cemented but still competent Berea sandstone. Breakout failure occurs at the same locations around the borehole as above, but its final shape is best described as a narrow linear slot or fracture perpendicular to aft direction. Our interpretation of the mechanism forming this type of breakout is that it is related to the weak bonding between the quartzitic grains as inferred from the high porosity of the rock, which also implies less cementing matrix material between the grains. Under sufficient far-field stresses, high stress concentration around the hole (along the ah springline), causes the collapse of the weak and sparse matrix, and partially or totally debonds the quartz grains. The disaggregated grains spall off in non-dilatant fashion, creating a higher stress concentration behind them. This in turn facilitates further disintegration of the cementing matrix, and removal of additional grains along the ah spring line. The newly observed breakout type, different from any previously experienced, could have major significance in studying instability problems in wellbores intersecting poorly consolidated sandstones.

P.229
Thermoporoelastic Analyses of Inclined Boreholes
Authors: Li X. , Cui L. , Roegiers J.-C.
Published: December 2007

This paper presents an analytical solution for the combined temperature, pore pressure and stress distribution around a circular, infinitely long borehole drilled in a poroelastic media of infinite extent. The borehole is assumed to be subjected to a constant pressure and temperature difference applied by the drilling fluid, and the borehole axis is arbitrarily oriented with respect to the in-situ principal stresses. Utilizing a loading decomposition scheme, the problem is solved by the superposition of three fundamental problems: a thermoporoelastic plane-strain problem; an elastic uniaxial stress problem; and an elastic anti-plane shear problem. The potential impacts of non-isothermal drilling processes on inclined borehole stability are illustrated through an application example.

P. 443
The Effect of Phase Behavior on Recovery Efficiency with Micellar Floods
Authors: Lorenz P.B. , Bayazeed A.F.
Published: December 2007

Phase diagrams were developed for two oils and two combinations of petroleum sulfonate and alcohol to determine whether such diagrams are useful as a screening test for surfactants to be used in micellar flooding. The diagrams illustrate the effects of surfactant concentration, salinity, cosurfactant, calcium, and tripolyphosphate; temperature and pH effects were also examined. Because of the importance of rheological properties in recovery, an aqueous micellar fluid was properties in recovery, an aqueous micellar fluid was studied. Viscosity data were supplemented by conductance measurements to get a better understanding of the colloidal changes taking place. A few laboratory micellar floods showed an encouraging correlation with phase behavior.

Introduction

Because of the improved economic climate for tertiary oil recovery and the technological promise of micellar flooding, the Bureau of Mines is supporting the development of this technique in laboratory and field tests. Screening tests for micellar fluids are needed to determine the optimum formulation for a particular reservoir. particular reservoir. The term "micellar fluids" here designates emulsions produced by blending petroleum sulfonate, an alcohol as a "cosurfactant," and brines. The term applies to a surfactant at above its critical micelle concentration. There is no sharp boundary between micellar flooding and other types of surfactant flooding.

Since the pioneer work of Gogarty, Davis, and coworkers, fluids of higher oil content have been tested in the laboratory and field by Holm and others, and fluids of higher water content have been studied elsewhere. Related work with petroleum sulfonate surfactants has been reported from petroleum sulfonate surfactants has been reported from several laboratories. The various micellar fluids differ in viscosity and homogeneity, and in their response to salinity, temperature, and the presence of divalent ions.

It is often assumed that the most effective micellar fluids for tertiary recovery are those that best solubilize crude oil, but this assumption is open to some question. If, however, it can be supported by investigation, it could form the basis for screening tests. This was a major reason for undertaking the present work. present work.
Clean Air and the Petroleum Industry in West Texas
Authors: Short Charles Gregory
Published: December 2007

For a number of years the oil and gas fields of West Texas have supplied Texas and the nation with large amounts of fossil fuel. In recent years the Texas Air Control Board has adopted regulations which directly affect the exploration, production, and processing of these energy sources. The purpose of this paper is to show how adopted air pollution control regulations affect the various pollution control regulations affect the various phases of development of these fuel sources phases of development of these fuel sources in this age where concern for both a clean environment and abundant energy supplies is paramount. paramount

Introduction

In 1967, the 60th Texas Legislature passed the Texas Clean Air Act. The stated purpose of the Act was to "…safeguard the air resources of the state from pollution by controlling or abating air pollution and, emissions of air contaminants, consistent with the protection of health, general welfare, and physical property of the people, including the esthetic enjoyment of the air resources by the people and the maintenance of adequate visibility." The Act establishes the Texas Air Control Board as the state air pollution control agency, and names the Board as the "principal authority in the state on matters relating to the quality of the air resources in the state and for setting standards, criteria, levels, and emission limits for air contaminants and pollution control." The Act also provides for an Executive Director to be administrator of air control activities for the Board. His responsibilities include any and all things necessary to achieve the purposes and objectives of the Act and to purposes and objectives of the Act and to provide general supervision over all personnel provide general supervision over all personnel employed by the Board. The Executive Director has established 12 Air Quality Control Regions in the state. Within each region the Executive Director has established a regional office at a convenient location. These regions and their corresponding regional offices are designated in Figure 1. The Regional Supervisor is responsible for the operations of the regional office as well as all air pollution control activities within his assigned region. In January 1972 a regional office of the Texas Air Control Board, Air Quality Control Region 6, was established in Odessa, Texas. From the time of establishment of the Odessa regional office it became apparent that the largest number of air pollution problems in the region were those directly related to the production and/or processing of oil and gas from the rich deposits in West Texas. This paper is concerned with the air pollution problems encountered by the oil and gas industry in West Texas, and how that industry might operate in compliance with the Regulations established by the Board.
Prediction Of Overpressures In The North Sea
Authors: van Baaren C.
Published: December 2007

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. 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 publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request 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 Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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.

Overpressures are encountered on the North Sea in rocks of Tertiary to Permian age. The distribution of overpressures varies from basin to basin and examples are discussed.

The mud logging techniques such as d-exponent, temperature records and wireline logging techniques such as the sonic transit time - depth plot and the shale resistivity - depth plot may indicate overpressures in specific cases.

However the adjustment of mud weights and casing setting depths in exploration and appraisal wells in the North Sea, based on the overpressure prediction techniques, is not justified generally at present due to the unreliability of the methods.

Introduction

The term overpressure is used for formation fluid pressure exceeding the normal hydrostatic fluid pressure. The formation pressure gradients vary from 0.433 psi/ft for pressure gradients vary from 0.433 psi/ft for fresh and brackish water to approx. 0.465 psi/ft for salt water with a salinity of 80000 ppm NaCl eq. Appendix 1 shows the nomenclature used.

Overburden pressure gradients calculated from bulk density logs vary from 0.80 psi/ft at shallow depths to 0.95 - 1.0 psi/ft at greater depths. These values are in agreement with the formation strength data obtained from tests carried out below a cemented casing of which results are presented in Appendix 2.

Knowledge of the distribution of overpressures will make drilling safer and will attribute to more economical casing schemes.

OVERPRESSURE PREDICTION METHODS

A summary of the overpressure detection methods is shown in Appendix 3. One group of methods has to be applied during the actual drilling phase, while the methods in the evaluation phase can be applied after the hole is drilled.
Status of Midwest SNG Operations
Authors: Krol Casimir A.
Published: December 2007

This paper was prepared for the Second Midwest Oil and Gas Industry Symposium of the Society of Petroleum Engineers of AIME, to be held in Indianapolis, Ind., March 28–29, 1974. 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 request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A continued difficulty in meeting demand for natural gas has forced many gas utilities to seek supplementary supply by synthetic production. Particular interest has been drawn to gasification of petroleum fractions.

From 1972 throughout 1973 the number of interested companies has increased tremendously. A number of synthetic gas plants are presently operating in the Eastern part of the United States.

In the Middle West a considerable activity has taken place also. A number of plants are in start-up or operation and at least two (2) additional plants should be in full operation during the heating season of 1974–1975.

The Peoples Gas Light and Coke Company's SNG Plant is particularly unique in that being a grass-roots plant it had to be designed with extreme care to prevent any adverse environmental impact. prevent any adverse environmental impact. As a result, special systems and methods were incorporated into the plant's complex make-up.

Introduction

Most gas utilities instituted a major program in the late 1960's to find and develop new sources of natural gas. The continued growth of energy requirements in the nation made a severe impact on the entire gas industry. Natural Gas was being used to such a great extent that it represented about 40% of the total national energy used. Since wellhead prices were controlled and no deregulation was in sight, drilling incentive dropped off to such an extent that supplies to the nation were being decreased.

A study was conducted on the advisability of producing supplementary gas supplies through such means as synthetic gas production, importing of liquefied natural gas and development of Alaska gas fields. Unfortunately, satisfaction of demands by most of these methods was not envisioned until well after 1980. The actuality of this shortage was brought to the public when on July 16, 1973, the Federal Power Commission released a statement wherein it was estimated that 15 major interstate transmission companies would be forced to curtail their firm gas contract deliveries by 1.16 trillion cubic feet.
Reservoir Engineering Aspects of Oil Recovery from Low Permeability Reservoirs by Air Injection
Authors: Turta A. T. , Singhal A. K.
Published: December 2007

This paper addresses the reservoir engineering aspects of air injection as an Enhanced Oil Recovery (EOR) technique for low permeability light oil reservoirs. In its most successful form, the process is currently known as High Pressure Air Injection (HPAI), and has been applied in deep, carbonate reservoirs. The development of this process in conjunction with an application of the in-situ combustion (ISC) process to light oil reservoirs, as well as the main mechanisms pertaining to ISC and to gas miscible flooding, are analyzed. It is seen that various air injection processes can be classified, depending on their spontaneous ignition potential and gas miscibility at reservoir conditions, into four different processes. Based on an in-depth literature review, the best reservoir conditions for application of each of these four processes are derived. The main differences in operational aspects (pollution, corrosion, safety) for these processes are also discussed. Air injection can be applied either as a horizontal flood or as a vertical flood. For reef reservoirs, only a vertical mode of displacement is contemplated, while for non-reef reservoirs both these forms may be feasible. The application of air injection to fractured carbonate reservoirs is evaluated, although so far, the reported successful projects have been only in non-fractured carbonate reservoirs. A preliminary analysis shows that for fractured reservoir applications, only the vertical flooding mode is feasible. Design considerations for pilot testing of the technique are discussed, and the differences in piloting for a horizontal flood are pointed out. The crucial point is the location of the pilot on the structure, which is a key element in a proper evaluation of the pilot, and its subsequent development to a commercial size operation.

Finally, specific recommendations on laboratory work in support of design and evaluation of a field pilot are presented.
History Matching Gas Injection Processes with In-Situ Saturation Measurements and Process Hysteresis
Authors: Yu S. Y. , Akervoll I. , Torsaeter O. , Stensen J. A. , Kleppe J. , Midtlyng S. H.
Published: December 2007

This paper describes experiments and simulation of gas injection processes with hysteresis. Two complete gas- and oil injection cycles have been performed at the reservoir conditions of 300 bar pressure and 100 °C temperature under X-ray Computer Tomography (CT) surveillance to obtain oil and gas in-situ saturation values at irreducible water saturation. The reservoir condition core flood experiments were performed on restored North Sea reservoir cores with use of live pre-equilibrated oil and gas phases at reservoir conditions by separator liquid samples and excess gas.

The core flood conditions were designed prior to the physical experimental program by using a reservoir simulator. The basis for the history matching was the CT in-situ saturation measurements of oil and gas in six cross sections along the length axis of the core versus pore volumes (PV) of equilibrium gas injected, oil and gas production volumes versus PV injected and the differential pressure recordings across the core during the injection experiments.

The experiments are history matched by use of the ECLIPSE reservoir simulation package. In this procedure the well completions are specified with an explicit transmissibility factor. Injection and production dummy grid blocks are connected to inlet and outlet end of the simulation grid. The production wells are controlled by either bottom hole pressure or the total reservoir fluid rate; the injection wells are rate controlled according to the physical rates. A systematic sensitivity study by isolating variables has been done in matching production history, in-situ saturation values of gas and oil, and differential pressure recorded in the displacement experiments. The analysis of the results has identified the most important dynamic reservoir parameters and characteristics that control the recovery mechanism during each displacement sequence of the gas and oil injection experiments. The hysteresis functions in the two-phase gas-oil injection sequences have been investigated.
Design and Execution of the Alison Horizontal Multilateral Project
Authors: Morgan D. R.
Published: December 2007

The Phillips operated Alison field in the UK North Sea produces gas from a low permeability layered Rotliegendes sand reservoir. The field was developed with a single subsea well producing out of three horizontal laterals. Four laterals were drilled. The first lateral encountered a fracture system and was abandoned to eliminate any risk of producing water through the fractures. The second lateral was completed with a slotted liner in layer C, the tightest but thickest layer in the reservoir. Following a production test of this lateral, the third and fourth laterals were drilled in layers B and D respectively and completed open hole.

Phis paper will discuss various aspects of the project, including drilling the horizontal section for each of the laterals, the tools and techniques used to abandon the first lateral, and the different methods used in establishing the junctions concentrating on the open hole junction used to establish the fourth lateral. The success of the open hole junction in this well has resulted in the use of this technique for wells in other developments, including one example where a lateral was drilled to TD, the junction established and drilling continued in the second lateral without a trip.