bluuebunny/crossref_metadata_2025 huggingface dataset:
Studies Dispel Myths, Give Guidance on Formulation of Drilling Fluids for Shale Stability
Authors: Simpson J.P. , Walker T.O. , Aslakson J.K.
Published: December 2007

Shale instability problems when using water-base drilling fluids have remained unresolved for decades because of a lack of knowledge and understanding of the shale hydration mechanisms. The industry has relied upon hydrocarbon-base drilling fluids for combating shale problems, but misconceptions have kept even those fluids from being utilized to their fullest advantage. With the use of hydrocarbon-base fluids now being curtailed because of environmental concerns, costs due to shale problems could escalate.

The understanding of shale instability problems has been hindered by inadequate laboratory means of simulating contact of drilling fluid and shale under downhole conditions of stress and temperature. To address this situation Gas Research Institute has conducted a project in which laboratory equipment and procedures were developed to permit preserved specimens of downhole shale (cored in hydrocarbon-base mud) to be restored to in situ axial stress, horizontal stress, pore pressure and temperature prior to being drilled at a selected borehole pressure. Provisions were made for measurement of fluid transport in either direction between the circulating drilling fluid and the shale during an extended period of exposure. The borehole pressure was then reduced incrementally to observe for borehole failure and obtain a measure of effect of the drilling fluid on the relative stability of the shale.

The above procedures have been used to study a well- known troublesome Cretaceous shale cored using oil-base mud at a depth of about 5,500 ft in Block 4 of the U.K. sector of the North Sea. This paper presents data showing that the aqueous activity of either a water-base or hydrocarbon-base emulsion drilling fluid can be adjusted to develop osmotic pressure that will cause water to enter or be extracted from a low-permeability shale. The hydraulic differential between the borehole pressure and far-field shale pore pressure is also shown to be a driving force affecting the transfer of water.

Discussion of these test results dispels several existing myths and provides guidelines for more effective use of current drilling fluids. The results also provide guidance for development of new environmentally acceptable water-base systems for combating shale problems where the use of hydrocarbon-base fluids is not permitted.

P. 731
Radio Communications in the Petroleum Industry
Authors: Stover Jerry S.
Published: December 2007

Introduction

Communication is the nervous system of industry and it takes many forms. Letters, memos, telephone, telegraph, and personal conferences all play their important part in the control and direction of industrial operations. This is particularly true in petroleum operations where time is often of the essence. A paradox has existed, however, because in field operations, where time usually reaches its greatest value, the ability to communicate has often been severely restricted. The advent or practicable field radio communications has now provided this essential link in the communications chain. Because its application is so widespread, petroleum engineers may frequently be called upon to consult with the radio engineer in the design of a system for an oil company's particular operation. The petroleum engineer with a detailed knowledge of his company's operations, together with a working knowledge of radio can be of material assistance in the system design. The purpose of this paper is to provide the petroleum engineer with a general description of the various types of petroleum radio systems, capabilities, limitations, cost and operating features.

Drilling Operations

Radio communication was initially used in drilling operations shortly after World War II, when rugged FM (Frequency Modulation) equipment suitable for the severe operating conditions of drilling rig use was developed. The basic drilling rig system consists of a station installed on the drilling rig and a mobile station installed in the toolpusher's car. This provides communication with the rig at all times, enabling the pusher to contact the rig to see what supplies are needed before driving out from town. More important, the rig is able to contact him at any time.

Special extension control units can be plugged in so the toolpusher may receive and send messages from his bedside at night using the station in his car. Because the antenna of the drilling rig station is located atop the 120 ft derrick, this basic system, a rig unit and car unit, has an operating radius or approximately 35 miles, and costs approximately $1800.

Oil companies or drilling contractors that operate a number or rigs within a 60 to 100 mile radius of a field office frequently install stations at the office. Drilling reports, requests for supplies, orders, etc., can be transmitted directly between the office and rig at any time. If the office is closed at night, a remote control unit is often installed in one of the employee residences to permit handling of emergency night calls. An office station with an operating radius to drilling rigs of 50 to 60 miles costs approximately $1,000. A more powerful station, with high antenna for communication range up to 100 miles, costs $6,000 to $8,000.
Acoustiviewer - A New Method for Inspection of Down-Hole Tubular Goods
Authors: Schaller Herman E. , Kilpatrick Robert , Stratton Robert
Published: December 2007

Utilizing a down-hole acoustical scanning device, parted casing, split pipe, enlarged slots, holes and other abnormalities in pipe can be identified. The obvious importance of this information can be a controlling factor in remedial work. First, the precise location of the problem is identified in a relatively short time and recorded at the surface. Secondly, the scope of the problem is defined which enables the optimum planning for corrective action. To date the field results with this tool have been limited to the Los Angeles Basin.

INTRODUCTION

Sub-surface mechanical problems are inherent in the exploitation, development and production of oil reservoirs. Included in these problems are corroded pipe, partially collapsed pipe, split casing, parted or sheared casing, enlarged perforations. The severity of the damage may range from a potentially serious condition to one in which the well becomes completely ineffective. The latter condition has been experienced when sub-surface movement of strata occurred and in the Wilmington field has required special completion techniques to try and prevent reoccurrence of such casing failures.

In order to locate and attempt to identify the nature of down-hole mechanical failures it has been the practice to run feelers, impression blocks, caliper surveys, casing inspections, packers to pressure-test casing, impression packers and where conditions permit, photographic devices. Each of the above may be helpful in defining the problem but even a combination of several may still not provide the desired information.

In 1968, Mobil Research and Development Corp. announced a 'new and unique logging tool, called the Borehole Televiewer' to provide a means 'to inspect boreholes and to evaluate formations'.1 This new tool was 'primarily developed to evaluate fractured reservoirs . . .' 'The borehole can be filled with any homogenous gas-free liquid such as fresh water, saturated brine, crude oil or drilling muds. This tool takes an 'acoustic picture' of the borehole wall. The resulting log is a representation of the bore-hole wall as if it were split vertically and laid flat.' 'Any physical changes in the borehole wall are seen as changes in picture intensity. In this way, fractures, deformation or pits are reflected on the log.'1
Factors Affecting Foam Circulation in Oil Wells
Authors: Millhone Ralph S. , Haskin C.A. , Beyer A.H.
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.

The utility of aqueous foams as circulating fluids in wells with low bottomhole pressure has been established. Although foams are simple to prepare, their behavior to changes in flow and well parameters is complex. The effects parameters is complex. The effects on foam flow of a number of these parameters were investigated by parameters were investigated by using a computerized mathematical model developed from newly reported research. Trends in job design factors such as injection pressure, bottomhole pressure, pressure, bottomhole pressure, circulation time and lifting ability are shown to be related to flow velocity and the liquid volume fraction of foam. A series of figures, some operating rules and a table summarizing directional trends of these design factors for a number of the more important flow and well parameters are presented. It is concluded that foam job design studies should be done when new lob objectives, well configurations or fields are encountered.

Introduction

The effectiveness and economic attractiveness of aqueous foam as a circulating fluid in well cleanout and drilling operations has been shown. Foam is increasingly important for a wide variety of oil field work where its low density and relatively high solids-lifting capability are needed. Foam has been successfully used in conventional and thru-tubing operations both onshore and offshore, in hard rock and soft sand provinces, and in permafrost areas. A vast amount of permafrost areas. A vast amount of experience with this unusual fluid is now commercially available from a number of service companies who have completed approximately two thousand foam circulation jobs.

Prediction of optimum gas and liquid rates, pressures, circulation time or solids-lifting ability is often difficult because of the complexity of foam circulation in wells.
Long Term Deliverability Forecasts for Dual Porosity Gas Reservoirs
Authors: Agarwal S.K. , Beveridge S.B.
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.

It is well recognized that the field deliverability of dual porosity reservoirs does not follow the projections made using standard analytical or two dimensional modelling techniques. Although the literature reports a number of methods to analyze the pressure buildups for such reservoirs, these methods do not provide a means of computing long term deliverability.

This paper discusses the use of three dimensional modelling techniques to determine reserves and to project the deliverability of dual porosity gas reservoirs. The two field applications presented include:

a naturally fractured reservoir, and a reservoir where severe stratification makes it behave like two or more independent reservoirs communicating through shale-breaks or "windows" between them.

The pressure buildups recorded in these fields are unusual. Wells with core permeability of 20 to 40 md continue to buildup for more than fifteen months and exhibit an extraordinary rise near the end of the shut-in period. A history match using the above model resulted in the determination of the pore volume of each porosity system and the "flow capacity" between these systems. The model, for the prediction of deliverability, simultaneously solves the equations describing flux flow through the reservoir, the wellbores, the tubings and the surface system. Results show that the effect on deliverability of changes in the surface gathering system, number of wells or the operational strategy will be seriously miscalculated if the dual porosity effect is not considered.

Introduction

The ability to accurately forecast gas field deliverability under various operating conditions is a necessity for the optimum exploitation of any gas reservoir.
A Review of the Consolidation and Rebound Processes in One-Dimensional Porous Columns
Authors: Raghavan R.
Published: December 2007

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.

A review of the progress made in the last 5years is presented. Modern methods of analysis as they relate to oilfield operations are examined. Darcy's law and its implication as related to a mobile matrix are examined. The specific problem considered is a one-dimensional shrinkage or expansion of a porous system to a step function change in pressure at the base of the column that may be considered to be either semi-infinite or finite.

The theory presented in the review includes general forms of formation conductivity and pressure and couples the movement of soil particles and the associated mass flow of liquid. It is shown that the latter effect is extremely important. Further, the differences between consolidation and rebound (imbibition)processes are examined.

It is shown that, even though a nonlinear equation results, analytical solutions exist for a class of problems. Illustrative examples are presented. The nonlinear equation has also been solved numerically and the solutions obtained have been correlated with constant property through a transformation that is similar to the real gas-pseudopressure.

The effects of the overburden and gravity are examined separately. One aspect of consolidation or rebound that has resulted inconsiderable confusion is the choice of coordinate system (moving or stationary) to develope the mathematical model. This aspect is also examined in detail in this review.

Introduction

For over 3 decades, subsidence of the land surface has attracted the serious attention of a large number of workers in a wide variety of disciplines. More recently, there has been an added attraction mainly due to the environmental awakening, for man's activities have begun to inadvertently produce effects of considerable magnitude and human consequence.

It is well known that a number of mechanisms operate whereby the land may collapse (see studies of Allen, wherein it is shown that the subsidence and compaction may be a result of a wide variety of disparate causes either natural or as a result of man'sactivities). Irrespective of the cause of the sinking of the land, mathematical models developed to understand and predict subsidence are based on the pioneering work of Terzaghi. Most of these analyses involve the basic assumptions of Terzaghils analysis, even though some of them do take into account the variation of permeability, compressibility, and the like.(See, for example, the papers by Biot and Davis and Raymond and texts by Jaeger and Wu.)
Alternate Injection of HPG and Water - A Two Well Pilot
Authors: Dyes A.B. , Bensimina A. , Ait Saadi A.M. , Khelil C.
Published: December 2007

Many areas of the Hassi Messaoud oil reservoir in Algeria are undergoing miscible displacement by high pressure gas injection. Because of extreme reservoir heterogeneity and the unfavorable mobility ratio of miscible displacement by gas injection, the sweep efficiency, particularly the vertical sweep, is poor. As a result a two well pilot operation was started in the field in late 1968 to:

study the improvement in the sweep which could be achieved by following a miscible high pressure gas front with the alternate injection of gas and water, and study the injectivities and gas-oil ratio control of the process.

Ways to improve the injectivities and any problems which arise after water breakthrough are also to be studied. The pilot is still in progress but results are now available on the sweep, injectivities, and gas-oil ratio control

Breakthrough of the gas front into the producer occurred after 6 months of producer occurred after 6 months of injection but the water-gas front has not yet broken through after 32 months of injection. The gas front achieved a 22% volumetric sweep at breakthrough. The water-gas front has not yet broken through and has achieved a volumetric sweep of at least 85%. These are to be compared to a volumetric sweep of 10% to 12% at gas breakthrough for-gas injection alone in other areas of the field.

Miscible displacement ahead of the water-gas front has been continued by the maintenance of a free gas band. The gas-oil ratio production after gas breakthrough has been held to only 10% above solution by controlling the ratio of gas to water injected per cycle. A cumulative injection ratio of gas to water within the reservoir of 1.1 to 1.2 gave the desired results. This was in agreement with the design based on relative permeability curves.
Alternate Paths to Oil and Gas Supply from Domestic Sources
Authors: Searl Milton F.
Published: December 2007

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be 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 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 energy supply pattern projected in the National Petroleum Council's Initial Appraisal has been widely accepted as a forecast of the future even though not so intended and even though it does not appear to be a highly probable case. Other policy and supply options exist, including the option of placing greater reliance on North American sources of supply and relying on market prices and perhaps expanded research and development to bring forth the necessary supply. Some of the alternatives to the Initial Appraisal supply pattern may be more cost efficient from a national standpoint.

The prevailing view of the nation's future energy supply appears to be essentially that presented in the National Petroleum Council (NPC) Initial appraisal Petroleum Council (NPC) Initial appraisal of the U. S. Energy Outlook. (1) It is unfortunately that this initial appraisal has been widely accepted as representing the future course of events. The report's projections do not appear to be inevitable projections do not appear to be inevitable or even highly probable. The somewhat uncritical acceptance of the Initial Appraisal projections as a forecast of the future by some members of the industry and others tends to obscure the possibility that the nation may have real choices in the matter of energy supply within the period to 1985 as well as beyond. Moreover, period to 1985 as well as beyond. Moreover, some of the choices may be more cost efficient from the nation's viewpoint than the alternative represented by the Initial Appraisal projections.

The NPC report itself recognizes that the price, cost, and other economic assumptions on which its projections are based are only a "status quo" reference set and not maximum likelihood estimates of future economic parameters.
Environmental Planning For New Energy Resource Development On Public Lands
Authors: Stone Reid T. , Johnson Harry R.
Published: December 2007

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be 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 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.

Spurred by an ever-increasing demand for clean energy and dwindling supplies, interest has been renewed in the energy resources found on public lands. Before these resources can be developed, potential environmental effects must be weighed against the benefits to be derived from their use. A national concern for environmental quality has been translated into policy by the National Environmental Act of 1969.

Complying with the requirements of the Act for new energy resources development on public lands is a complex undertaking requiring public lands is a complex undertaking requiring (1) clearly defined program objectives, (2) an organization which can integrate public policy with diverse scientific disciplines, and (3) flexibility to adjust planning as various sections of the Act are clarified by Court decisions. This discussion explores the interrelationship between these factors using, as an example, the planning and organization created specifically to develop the Department of the Interior's Proposed Prototype Oil Shale Leasing Program.

Introduction

In September, 1972, the Department of the Interior filed with the Council on Environmental Quality one of the most complex draft environmental statements ever prepared. Some 1,200 pages long, it was prepared. Some 1,200 pages long, it was nearly three years in preparation by over 200 professionals of widely diverse backgrounds.

The statement details a program designed to stimulate commercial oil shale development and describes the potential environmental consequences of that development however, the program itself has greater significance beyond the specific environmental concerns related to oil shale development.
The Use Of Dispersants In Cement Slurries To Improve Placement Techniques
Authors: Boughton L.D. , Pavlich J.P. , Wahl W.W.
Published: December 2007

Publication Rights Reserved

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 considered for publication in one of the two SPE magazines with the paper.

Field results indicate that displacing cement in turbulent flow during the primary cementing operation has materially reduced remedial cementing. Lower displacement rates with subsequently reduced frictional pressures have been achieved by using dispersants or thinners in the cement slurry. Failures caused by lost circulation and formation breakdown during primary cementing, sometimes encountered when high displacement rates are necessary for turbulent flow, have been substantially reduced.

The paper presents laboratory analyses of the effects of some dispersants on the rheological properties of cement slurries. These dispersants include (1) lignosulfonates; (2) phosphates; (3) alkyl-aryl sulfonates; (4) synthetic polymers. Such dispersants probably function somewhat like viscosity-reducing agents in muds, although the viscosity resulting from the gel structure of the hydration products apparently is reduced also.

Results on actual jobs using slurries containing thinners investigated are discussed. These results indicate that laboratory rheological measurements on slurries can be used successfully to predict pump rates necessary to achieve turbulency. Cementing operations using both low- and high-velocity displacement rates are compared.

Introduction

High displacement rates required during casing cementing operations to improve mud displacement impose certain restrictions limiting use of this technique. Specifically, rheological properties of many commonly used cement systems preclude approaching turbulency in the annulus because the frictional pressures induced at the critical velocity approach or exceed the formation breakdown pressure.
A Simplified Approach To Pressure Prediction And Well Planning In The Rocky Mountain Area
Authors: Morton D.H. , Vesely D.P.
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, Wyo., 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 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.

Generalized methods for determining pore pressures and fracture gradients have been pressures and fracture gradients have been developed for the Rocky Mountain Area. These methods, utilizing sonic log data and wellsite measurements, are based entirely on empirical data.

A generalized fracture gradient chart and formation density overlay has been developed to assist in well planning and mud density control.

Introduction

Methods for determining pore pressures from logs have been used on the Gulf Coast, and accepted for several years. These methods have not been as useful in the Rocky Mountains and other "Hard Rock" areas; lithology changes are frequent and drilling may progress from Tertiary to PreCambrian rocks on a single well.

Known methods for determining fracture gradients generally yield much higher values than are normally observed in the Rockies. This may exist since much of this area is naturally fractured.

Shale density overlays developed on the Gulf Coast have little application at most Rocky Mountain drill sites. These overlays were developed for use, with good clean shales which are uncommon in the Rockies.

A method for predicting pressures from sonic logs 51 was developed by examining these logs and comparing them with mud records. High and low pressure zones can be defined from the sonic plot, and the maximum mud weight required can be estimated by using a simple method.

A fracture gradient chart has been prepared by using mud records and sonic log prepared by using mud records and sonic log data.

A formation density overlay developed from several observed wells is submitted as an alternate to those previously developed.

SONIC LOG METHOD

The conductivity and resistivity methods of pressure profiling provide erratic data in the Rockies, since good clean shales are hard to find. Sonic logs will provide excellent data that are affected little by lithology (Fig. 1) if the values are averaged. Either the one- or two-inch per 100-foot scale will facilitate data averaging.
Adsorption and Desorption of Corrosion Inhibitors in Anaerobic Brine
Authors: Blair Charles M.
Published: December 2007

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 simple procedure is described for measuring instantaneous corrosion rates in brines under conditions simulating those encountered in the field. Rates of adsorption and desorption of n-dodecylamine inhibitor in mildly acidic, anaerobic brine saturated with carbon dioxide were inferred from corrosion rate measurements. Adsorption rates were also studied in brine saturated with hydrogen sulfide.

Both adsorption and desorption rates appear to be strongly dependent on concentration of the inhibitor during the adsorption period. Where adsorption equilibrium is approached slowly desorption rates in uninhibited brine appear to be very slow.

The results lead to suggested methods of improving field application of inhibitors.

Introduction

Almost twenty-five years ago it was discovered that the very severe corrosion problems occurring in petroleum production and refining equipment could be petroleum production and refining equipment could be mitigated by adding small concentrations of certain classes of cationic, surface-active compounds to the fluids involved. With suitable formulation and application these products have been found broadly effective in most typical oxygen-free systems containing hydrocarbons.

Large volumes of corrosive anaerobic brine are now handled in the oil fields, especially in the United States. Somewhat surprisingly, the use of the familiar cationic inhibitors in such brines has been generally disappointing. The degree of inhibition has been limited or costly concentrations have had to be used continuously.

A principal aim of the present work was to study the behavior of cationic inhibitors in mildly acidic brines with the aim of elucidating their behavior and, hopefully, finding means to improve their effectiveness. A special aim of this work was to devise a means of studying rates of adsorption and desorption of inhibitor films.

Earlier work with oil and brine fluids from oil wells indicated that organic inhibitors function in such systems by adsorbing on the exposed metal surfaces to form very thin — possibly monomolecular — films which present a barrier to corrosion reactions.
Rx for Gumbo Shale Drilling
Authors: Allred Robert B. , McCaleb Stanley B.
Published: December 2007

Exploration strategies have caused large investments in the search for offshore production. Many of these areas are characterized by poorly consolidated sediments and associated problems of gumbo shales. These problems not only slow down problems of gumbo shales. These problems not only slow down drilling procedures, but in some cases may cause the loss of the hole. These offshore areas have high hydrocarbon potential and high drilling costs. Control of gumbo shales during drilling has become the number one problem in these areas.

Many papers have been written on gumbo shale drilling but usually the control method is based upon a particular remedy not necessarily applicable to all cases. This paper explores the nature of gumbo shales and presents a survey of the many remedies that have been recommended. Solutions to the effective drilling of gumbo shales are suggested based upon the nature of the shale.

Drilling fluid design is the cure for problems caused by gumbo shale. Five remedies for controlling gumbo problems have been used:coating the shale surface,inhibiting the shale,removing water from the shale osmotically,controlling shale influx by increasing the hydrostatic head, andremoving shale cuttings from mud.

The drilling fluid components used for each of the five control measures are evaluated in terms of effectiveness in the different types of gumbo shale. Prescriptions for drilling fluid control are suggested utilizing the five methods of control. Drilling rates and solids removal equipment are also discussed as they contribute to the gumbo shale control problem.

There are some very effective remedies for gumbo shale problems but the proper treatment must be used for a specific kind problems but the proper treatment must be used for a specific kind or type of gumbo shale problem. A new Sun invention will be disclosed as a gumbo control device.

Introduction

Gumbo shales are composed of a range of materials which either have a very high content of silt-sized and/or clay-sized materials or a very high content of minerals of the montmorillonite type. Both become exceedingly sticky and tenacious when water contents are high. The great plasticity which results causes the gumbo to stick to surfaces and when mechanically mixed or sheared builds up large plastic masses.
Field Preparation of Polymer Solutions Used to Improve Oil Recovery
Authors: Schurz George
Published: December 2007

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.

Polymer solutions used to increase oil recovery by waterflood are prepared with automated equipment which dissolves dry polymer powder in flood brine. Proper equipment design, powder in flood brine. Proper equipment design, compatible brine and correct polymer selection are essential to providing a polymer solution which exhibits good mobility control at lowest cost and which retains mobility control throughout the life of the flood. Brine requirements, equipment arrangements and additives for a variety of field conditions are discussed.

Introduction

High molecular weight polymers are increasingly used to improve sweep efficiency in waterfloods. Improved sweep is obtained because the polymers reduce the mobility of the water polymers reduce the mobility of the water Polymer is used during a substantial part of the Polymer is used during a substantial part of the flood life, a period of several years, so that efficient, economical means of preparing the polymer solutions are required. polymer solutions are required. Preparation of the polymer solution require the blending of dry polymer powder with brine to form a slurry, this slurry is given sufficient dissolving time and finally the solution is injected into the formation. This paper will discuss the properties of the polymers used, required properties of the brine, mechanical equipment needed and the methods of solution quality control used.

POLYMER PROPERTIES POLYMER PROPERTIES Prior to the start of the field operation, the proper polymer is selected on the basis of laboratory studies using cores and fluids from the field in question. The mobility of the crude oil, of the brine used, and of the polymer solutions at various strengths is measured in the field cores. From these measurements, a flood play is developed for the most profitable operation. This plan specifies the amount and use rate of polymer and the laboratory measurements define the properties of the solution which must be handled in the plant.

Specifically the properties to be discussed in this paper refer to PUSHER chemicals. These are a family of partially hydrolyzed polyacrylamides especially manufactured for waterflood use. polyacrylamides especially manufactured for waterflood use. As furnished, PUSHER chemical is a finely ground, moderately hygroscopic powder supplied in 50 pound sacks, 250 pound drums or as bulk material pound sacks, 250 pound drums or as bulk material in hopper cars or trucks. Bulk density of PUSHER chemical is 42 pounds per cubic-foot. PUSHER chemical is 42 pounds per cubic-foot.
A New And Fast Method For Solving Large Numbers Of Reservoir Simulation Equations
Authors: Routt Kenneth R. , Crawford Paul B.
Published: December 2007

1973 Third Symposium on Numerical Simulation of Reservoir Performance, Houston, Texas January 11–12, 1973. Performance, Houston, Texas January 11–12, 1973

Computer modeling of petroleum reservoirs leads one to the problem of solving large numbers of simultaneous fluid flow equations. The purpose of this paper is to propose a new method for solving these equations and present comparisons between our method and the strongly implicit procedure (SIP) proposed by Stone and others. We have compared the new technique with SIP for a number of two-dimensional, steady state problems in both homogeneous and strongly heterogeneous reservoirs, with reservoir sizes ranging from 100 to 800 blocks. For some heterogeneous cases the ratios of transmission coefficients varied by a ratio of one million to one for testing. Compared to SIP, our method requires less computer storage space, compiles faster, executes up to 2.96 times faster, has no iteration parameter, is easier to program, requires about two-thirds an many cards, and gives excellent agreement in regard to material balance and final values of Pi,j. The method has been applied to problems with from 2 to 16 wells positioned in the reservoir corners, immediately adjacent, in line, and in random positions. Well magnitudes have been allowed to range up to a ratio positions. Well magnitudes have been allowed to range up to a ratio of 10,000 to 1.0 in the same problem. For every problem thus far attempted, the method has converged to the same answers as SIP in less computer time. Based upon our experience with this new method, we feel that the new method is substantially superior to SIP.
A Generalized Model For Predicting The Performance Of Gas Reservoirs Subject To Water Drive
Authors: Katz Donald L. , Tek M. Rasin , Jones Stanley C.
Published: December 2007

Publication Rights Reserved

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 considered for publication in one of the two SPE magazines with the paper.

A calculation procedure for predicting the performance of water-drive gas reservoirs without the usual assumptions of simplified geometry and homogeneity is presented. A characteristic pressure drop curve for a constant rate of water influx is calculated from field-performance data. Its extrapolation allows prediction of future water movement and pressure behavior when a projected production or pressure schedule is given.

The procedure has been extended to handle "moving boundary" problems resulting from the growth of the gas bubble in early stages of aquifer storage.

Two field case histories are presented where predicted performance is compared with direct field data.

Introduction

Gas reservoirs adjacent to water bearing formations are subject to water movement resulting from fluctuations in the gas bubble pressure. The rate of this water movement has been an area of interest to oil and gas production and storage industries for some time. The recent advent of aquifer storage, where the pore volume necessary for the storage of gas is created through the expulsion of water from its native formation by pressurization above discovery level is perhaps the most prominent example where the information on the extent and the nature of water movement is desired.

Solution of the diffusivity equation governing the movement of water in aquifers has been given in the literature for various geometries. These solutions are all based on some simplifying assumptions such as: uniform formation properties, gas bubble of constant volume, etc.
Numerical Simulation of the Zarzaitine Devonian F4 Reservoir, Algeria
Authors: Dorsey J.B. , Jones L.D. , Bencheikh A.
Published: December 2007

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 principal producing reservoir of Algeria's second largest oil field, Zarzaitine, has been studied using a three-dimensional reservoir simulator. When the study was conducted, the reservoir had been producing for over 10 years, the last 5 of which had been with peripheral water injection. The primary objective of the study was to determine how to maximize current production without sacrificing a significant quantity of ultimate recovery. To accomplish this objective required, first, attaining a reasonable match of past performance and then investigating future field operational techniques. A five-layer, three-dimensional, three-phase model was used to accomplish this objective.

A one-dimensional model was used extensively to first evaluate overall reservoir volumetrics, then nine 3-D runs through various periods of performance history were required to obtain an acceptable match of gas- and water-oil ratios and reported bottomhole pressures. To develop the match it was pressures. To develop the match it was necessary to adopt a multiple kg/ko correlation and, since bubble-point pressure varied with depth, it was necessary to account for depthwise changes in fluid properties.

Predictions of future reservoir performance under three plans of operation were performance under three plans of operation were studied with the model. An elaborate prediction routine which provided for the effects prediction routine which provided for the effects of tubing size and gathering-system pressure on productivity and injectivity was used in the study. In the course of these predictions, additional drilling, workover of predictions, additional drilling, workover of existing wells, cycling of the reservoir's gas cap, and various water-injection programs were considered in arriving at a recommended optimum plan of operation.

It was concluded that the 1-D and 3-D model combination provided a practical and accurate means of evaluating the Zarzaitine F4 reservoir.

Introduction

The Zarzaitine field is located in the Sahara Desert of southeast Algeria and is one of that country's major fields (Figure 1). Discovered in 1957, it has a productive area of approximately 35 square miles and produces from several horizons. The major reservoir is a series of Devonian sandstone members designated as the F4 which initially contained about 2 billion stock tank barrels in place.
Reversible Cross Linking in Oil Recovery
Authors: Friedman R.H.
Published: December 2007

This paper was prepared for the Oilfield Chemistry Symposium of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., May 24–25, 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.

Construction of an oleotropic, or oil seeking, post primary fluid is described. Multiple viscosity levels are possible for a polymer solution depending upon the degree of crosslinking of the polymer. Cross-linking is dependent upon the presence of a highly oil-soluble, barely water-soluble "trigger." Extraction of the "trigger" at the oil-water interface effects viscosity reversal.

Introduction

Two limitations have generally limited the use of fluids designed to effect the post primary recovery of oil. one of these is economic, the other technical. then the product to be recovered can be sold for very low price, the product injected to price, the product injected to replace it must be purchased for markedly less. This constraint has all too frequently been ignored.

Techniques for recovering oil, for example, miscible displacement and surfactant recovery methods, have been mainly concerned with reducing oil saturation in the regions of the reservoir traversed by the injected fluid. Most petroleum engineers would agree that at the termination of a water flood, most of the oil remaining in the reservoir is in those portions of the formation not traversed by water. The primary function of a post primary recovery fluid ought to be the complete traverse of the entire oil-bearing region. Reduction of oil saturation within that region must be considered a secondary objective.

SYSTEM DESIGN AND CONSTRUCTION

The goal of the research effort to be described was the creation of a self-conforming post primary fluid which was to cost not more than 25 cents per barrel. The fluid was planned to per barrel. The fluid was planned to demonstrate a variable tendency to flow in different portions of the formation.