bluuebunny/crossref_metadata_2025 huggingface dataset:
Results of Waterflooding Some High Watercut Reservoirs in South Louisiana
Authors: Poston S.W.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

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 effects of waterflooding four high watercut, partially pressure-depleting South Louisiana reservoirs are discussed. In all cases, the secondary reserves estimates had to be increased after response to water injection had been established. Subsequent to response, an engineering re-evaluation indicated the primary production mechanism had been primary production mechanism had been misinterpreted and the original secondary reserves estimates had been unnecessarily conservative.

The installation and operation of a waterflood project in a South Louisiana salt dome associated field is subject to several variables. The fault patterns are quite complex and the deltaic-type deposits produce sands with erratic continuity. Intrawell sand correlation is oftentimes difficult. The areal extent of these Miocene reservoirs are usually never more than 500 acres. Also, wellbore availability is a constant problem. Due to the multiplicity of pay zones, neighboring wells may be dually pay zones, neighboring wells may be dually completed in different reservoirs. Water injection projects must often be initiated with a minimum number of wellbores and then gradually be expanded as other wells become available for recompletion.

Introduction

A study of the productive fields operated by Gulf Energy and Minerals Co. - U.S. in South Louisiana indicates few examples of pressure-depleting, nonwater producing reservoirs. pressure-depleting, nonwater producing reservoirs. In fact, reservoirs experiencing very efficient water drives with little pressure decline may display less associated water production than a structurally comparable partial water-drive reservoir. Significant pressure declines occur in many of these partial water-drive reservoirs when the water influx is incapable of offsetting the fluid offtake rate. Economic considerations often require the optimization of the rate of reservoir oil recovery.

The increased emphasis on maximizing oil recovery has resulted in a re-examination of the reservoir mechanics associated with oil production from the South Louisiana fields. production from the South Louisiana fields. The investigation revealed that the areal sweep efficiency may be quite low in some low relief, partial water-drive reservoirs. partial water-drive reservoirs. The-following study discusses four waterfloods operated by Gulf Energy and Minerals Co. - U.S. in South Louisiana. The reservoirs did not fit the classic picture for potential waterflood candidates.
Petrophysical Study of the Cardium Sand in the Pembina Field
Authors: MacKenzie Wm. T.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

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.

An evaluation technique to help define net pay and refine reserve estimates, and to aid in pay and refine reserve estimates, and to aid in optimizing productivity, was developed for the Cardium sand in the Pembina Field, Alberta, Canada. This technique is based on rock type as determined from mercury injection data. An empirical correlation between effective pore throat or aperture radius and the ratio of permeability to porosity (k/phi) was applied to permeability to porosity (k/phi) was applied to all core analyses on the Pembina "G" lease to generate suites of reservoir parameters such as net pay, pore volume, and flow capacity. When correlated with lease well productivity, they revealed wells with potential for improved productivity. Additional data from other leases productivity. Additional data from other leases in the field support the k/phi correlation validating its application to Cardium sand areas in the Pembina field. The technique is ideally suited to computer application.

Introduction

This petrophysical study of the Pembina "G" lease in the Pembina Field, Alberta, Canada, is part of a more extensive study of the Cardium part of a more extensive study of the Cardium sand reservoir. It was undertaken to obtain a better understanding of the reservoir characteristics and their relationship to the field performance. In areal extent, the Pembina performance. In areal extent, the Pembina field is the world's largest waterflood project. Thirty-four operators are active in 155 projects in the field. With some 921 million bbl of remaining recoverable oil reserves in the Cardium pool as of Jan. 1, 1975, there is incentive to obtain a better understanding of reservoir performance.

While some projects in the Pembina field are generally responding well to waterflooding, there are areas like the "G" lease where productivity is relatively low with a wide productivity is relatively low with a wide variation in well capability not explained by reservoir permeability, porosity or net par. Specifically, this study, in application to the problem at hand on the "G" lease, investigates problem at hand on the "G" lease, investigates the reason for the difference in well capability and defines wells with potential for improved production. A more fundamental purpose of the study is to provide an evaluation technique applicable to reservoir sand areas throughout the Pembina field which would aid in increasing productivity and refine oil-in-place and reserve estimates.

The approach utilizes mercury injection data and scanning electron microscope (SEM) studies of core samples to classify the Cardium sand into three basic rock types based on effective pore throat or aperture radii.
Influence of Cold Water Injection on Residual Oil Saturation of Multilayered Oil Reservoir
Authors: Rubinstein L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The paper contains information on the results of some calculations describing the influence of cold water injection on oil output from a multilayered oil reservoir. It is shown that there exists a real possibility of a complete or almost complete loss in productivity of a low-permeable sublayer adjacent to a highly permeable one, due to the filtration resistances permeable one, due to the filtration resistances redistribution under the influence of thermal interference of different sublayers.

Introduction

All large oil fields are exploited with the application of water injection in order to maintain the interlayer pressure. Usually each oil reservoir consists of a number of productive layers separated by relatively thin impermeable layers. Different neighboring productive layers are exploited simultaneously, being open by a well of unique face.

If the temperature of the injected water is lower than the initial temperature of the reservoir, the water injection can lead to the essential cooling of a relatively small permeable sublayer in front of an oil-water contact permeable sublayer in front of an oil-water contact moving inside it, but behind that in the most permeable layer. This is a consequence of permeable layer. This is a consequence of thermal interference of different productive layers.

If the volume of water injected into different productive layers can be maintained on a prescribed level, proportional to their physical permeability, such a cooling does not physical permeability, such a cooling does not lead to any sufficiently essential effects as well as heating of the stratum by injection of hot water. Unfortunately, in practice, the prescribed value is the pressure of injection on prescribed value is the pressure of injection on but not the distribution of water between different productive layers of the oil reservoir. By such a real system of speration the cooling (as well as heating) leads to a redistribution of resistances of oil and water to filtration. This redistribution may lead in some real cases to complete loss of productivity of low permeable sublayers or, in any case, to its almost permeable sublayers or, in any case, to its almost complete loss. Such a catastrophic consequence of cold water injection into multilayered oil reservoirs can be prevented by heating the injected water approximately to the initial temperature of the oil reservoir, and this action is economically admissible. Naturally such treatment must be applied from the beginning of the oil reservoir's exploitation.

Our aim consists of the demonstration of results of a number of calculations that were fulfilled some years ago on the base of the spatial developed methods. All these results were published in the author's book.
Case Histories of Design and Implementation of Underbalanced Wells
Authors: Giffin David R. , Lyons William C.
Published: December 2007

As operators strive to increase production from existing reservoirs with depleted reservoir pressure, the use of under-balanced drilling and underbalanced horizontal drilling is becoming more widely used. One of the primary problems to be overcome in drilling under-balanced is designing a circulating "fluid" that has an equivalent circulating density below the reservoir pressure. This paper discusses the mathematical equations used to design air drilled "under-balanced" wells. It will also show how these equations were used to design four separate wells. The presentation of actual field data will validate these equations and computer modeling used. The four wells will include 1) 17,000 TVD well drilled into the Ellenberger formation with reservoir pressure at 1200 psig, 2) horizontal well drilled into the Petit formation at 5900 ft. TVD with reservoir pressure at 210 psig, 3) horizontal wells drilled into the upper Penn Formation at TVD 7800 ft. and reservoir pressure of 1000 psig., and 4) deviated wells drilled into the Ellenberger formation below 13,000 feet TVD and reservoir pressure of 600 psig.

The mathematical equations used were developed by Dr. William C. Lyons of New Mexico Institute of Mining and Technology in Socorro, NM. Computer simulations for these wells were run by David Giffin on software developed by Boyum Guo and Dr. Lyons. Each of these wells was drilled using air drilling techniques. By measuring the pressure at both surface and bottom hole conditions, the validity of the mathematical models used has been established. Air or other compressed gas can be used to reduce equivalent circulating densities to accommodate almost any reservoir pressure.
Using 3D Seismic to Identify Spatially Variant Fracture Orientation in the Manderson Field
Authors: Gray David , Head Kim , Chamberlain Kent , Olson Gordon , Sinclair John , Besler Chris
Published: December 2007

Oil is produced from the Manderson Field, in Big Horn County, Wyoming, from a fracture system with possible significant lateral connectivity. So characterizing the fractures in this field is of great importance. Amplitude Versus Offset (AVO) analysis of azimuthally restricted seismic data is used to determine the orientation and density of fractures at selected locations corresponding to well locations in the Manderson field. The result of this analysis is compared to fracture strike analysis from oriented cores for three wells.
A Laboratory Study on Steam Distillation in Porous Media
Authors: Wu Ching H. , Brown Alfred
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Steam distillation investigations were made on crude oils in porous media to measure steam distillation yields and to determine the effect of process parameters on the distillation mechanism. parameters on the distillation mechanism. Experiments were performed in a vertically-oriented, 3-foot long, 3-inch diameter cell, designed to avoid steam displacement and entrainment of oil during steam distillation. Both saturated and superheated steam distillations were made on crude oils ranging in gravity from 9 to 36 deg. API. These tests were performed at pressures ranging from 200 performed at pressures ranging from 200 to 500 psig and steam temperatures ranging from 387 to 600 deg. F.

Experimental results show that the equilibrium saturated steam distillation yields are mainly dependent on the oil composition and may not correlate with crude API gravity. The yields are basically independent of the porous media and steam injection rates investigated. Changes in steam saturation pressure and temperature have insignificant effect on the yields; however, superheated steam significantly increases the yields for some crude oils.

Introduction

Steam distillation has been used chemical and other process industries for years. It is used as an alternate to processes requiring vacuum distillation to treat a feed stock at a temperature below the components' normal boiling point. These industrial steam distillations usually take place in cells not packed with porous materials.

Steam distillation of crude oil in porous media has been recognized as one porous media has been recognized as one of the major mechanisms responsible for high oil recovery by steam flooding. Willman et al estimated the oil recovery due to the steam distillation mechanism to range from 5 to 19% OOIP for various crude oils at steam temperatures up to 520 deg. F. Farouq Ali estimated that 5 to 10% of the heavy oil recovery by a steam flood may be attributed to steam distillation; and that as much as 60% of the oil recovery for some light oils may be attributed to the same mechanism. Volek and Pryor reported that in a field steam distillation drive test, the residual oil saturation in the steam swept region was less than 8%.
The Unified Analysis of Well Tests
Authors: Ridley Trevor P.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A technique has been developed for the unified analysis of pressure data, using information from all drawdown and buildup periods of virtually any test schedule. Best periods of virtually any test schedule. Best statistical estimates are obtained for values of initial reservoir pressure, permeability, skin factor and, if applicable, the nondarcy flow constant.

The fundamental reliability of the method is demonstrated by the precision with which it analyzes artificial test data. Analysis of field data from both oil and gas wells provides further strong support for the dependability of the technique.

The method is easily programmed on a computer for a regression analysis on many observations to give fast, reliable and inexpensive analysis of well-test data.

Introduction

The design of a well test is generally bound by constraints such as the need for constant flow rates, isochronal flow periods or stabilized pressures. These are required so that the test data can be reliably analyzed by an appropriate method.

The execution of a well test is often influenced by factors beyond the control of the testing crew. For example, it may be impossible to maintain a constant flow rate because of a varying backpressure on the well; a test may be disrupted by equipment failure; flowing pressures might not stabilize for weeks or pressures might not stabilize for weeks or months. Thus, test data may fail to meet precisely the specifications required by the precisely the specifications required by the particular analytical method. The choice is to particular analytical method. The choice is to retest the well in the hope of obtaining more suitable data, or to use the existing data recognizing that the results may not be entirely reliable.

Many analytical techniques ignore a significant amount of the data collected during the test. Horner's buildup analysis, for example, ignores all but the final flowing pressure of the drawdown period before shut-in. pressure of the drawdown period before shut-in. An isochronal test ignores the pressure data preceding the endpoints of each flow and shut-in preceding the endpoints of each flow and shut-in period. The multiple flow-rate analysis period. The multiple flow-rate analysis proposed by Odeh and Jones ignores all shut-in proposed by Odeh and Jones ignores all shut-in periods. periods.
Successful Matrix Acidizing of Sandstones Requires a Reliable Estimate of Wellbore Damage
Authors: Burkill G.C.C. , Lichaa Pierre M.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Successful matrix acidizing of sandstones for the removal of wellbore damage is dependent on a reliable estimate of wellbore "skin" and its radial extent. The value of these parameters is estimated from pressure-buildup parameters is estimated from pressure-buildup analysis. However, in depleted, multilayered reservoirs, the values obtained may vary considerably depending on the chosen method of pressure-buildup interpretation. pressure-buildup interpretation. For this study, pressure buildups before and after acidization were analyzed by both the semisteady-state solution of Horner and early time analysis of McKinley. These results were compared with the actual field results.

It may be concluded that the early time analysis of McKinley gave more probable results, but it should be stressed that, under these reservoir conditions, there is no absolute answer, and results from independent methods should be compared.

Introduction

At present, Cia. Shell de Venezuela is involved in an active stimulation program to optimize oil potentials from their Lake Maracaibo sandstone reservoirs. The choice of candidates and treatment design depends on a series of factors, but perhaps the most important is the extent of wellbore damage.

In the Horner method currently used, the skin factor and reservoir permeability are both determined by the slope of the linear portion of the buildup curve. If the linear portion of the buildup curve is chosen incorrectly, the calculation will yield either an excessive skin together with an overestimate of reservoir permeability or an underestimate of wellbore permeability or an underestimate of wellbore damage and a reduced reservoir permeability.

The present trend to "minifracs" (small frac treatments with sand using gelled gas oil as carrying fluid) for removal of wellbore damage does not depend too heavily on correctly interpreting the damage factor as the oil gains result from two mechanisms:skin removal if it exists, andincreasing the natural permeability in the nearby area of the well or permeability in the nearby area of the well or even fracturing into sands of improved permeability. permeability.
Constant Pressure Injection Test in a Fractured Reservoir-History Match Using Numerical Simulation and Type Curve Analysis
Authors: Locke C.D. , Sawyer W.K.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Water was injected at constant pressure into a single well in a pressure into a single well in a fractured reservoir for a period of 32 days followed by a 9 day shut-in period. Intake volumes of the injection well and pressure responses in 19 surrounding pressure responses in 19 surrounding wells were recorded during the entire test.

Type curves were generated by numerical and semi-analytical techniques to facilitate reservoir characterization from the constant-pressure, declining-rate injection data. A single-phase, three-dimensional, semi-compressible simulator was developed and used to match the field-results.

The fracture orientation trend of the reservoir was determined, and reservoir permeability and effective fracture length were calculated for the injection well. Type-curves are presented for use in evaluating the presented for use in evaluating the constant terminal pressure case for fractured wells.

Introduction

Hydraulic fracturing is used extensively to improve the economics of primary oil production and is being used increasingly in waterflood projects involving wells with severe skin damage, lower permeability reservoirs, and reservoirs with wells that were fractured for improved primary production. Previous fears that induced production. Previous fears that induced fractures may result in floodwater "channeling" to production wells are gradually dissipating as more is learned about the nature of these fractures. There is strong evidence to suggest that the vast majority of induced fractures are vertical and extend laterally in a preferred direction. Proper alignment of fractured wells for Proper alignment of fractured wells for pattern flooding can result in pattern flooding can result in displacement efficiency equal to or better than that of patterns using unfractured wells. Donohue, Hansford, and Burton investigated the effect of fracture orientation on displacement efficiency in pattern floods showing the importance of pattern alignment with respect to fracture direction.
A Practical Application of a Subsea Oil Production System
Authors: Chatas A.T. , Kin W.D. , Bendiks Carlos
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A typical field application is defined, where the objective is to utilize a subsea production system to develop an offshore oilfield in an average water depth of 800 feet. Eight dually completed wells are required to achieve a production plateau of 25,000 BOPD. The SEAL production plateau of 25,000 BOPD. The SEAL Multiple-Well Manifold/Production Station was chosen for this application.

Introduction

Anticipation of offshore petroleum discoveries in profoundly deep water engendered the research and development of various subsea production systems over the past decade. Some production systems over the past decade. Some of them are now considered operational and available for practical application. One such system, pioneered by Mobil and completed by SEAL, is the Multiple-Well Manifold/ Production Station, which will be incorporated here Production Station, which will be incorporated here in the development of an example offshore oilfield.

This multiple-well station is intended for use where deviated drilling is possible from subsea locations, where wells may be drilled peripherally through a base template. The peripherally through a base template. The wells are then connected to a subsea work enclosure by use of wellhead connector assemblies. Functioning basically as a manifolding station, the subsea work enclosure provides a dry environment on the sea floor at atmospheric pressure, in which normal oilfield equipment may operate.

The example field under consideration lies offshore in 800 feet of water, about a mile from an existing platform. It contains two reservoirs that will be produced through dually completed wells to achieve a field production rate of 25,000 BOPD. The wells production rate of 25,000 BOPD. The wells are to be drilled by a floater rig, deviated through the drilling template that will serve as the base of the multiple-well station. Production will be manifolded on the seabed Production will be manifolded on the seabed through the subsea work enclosure and piped to the nearby platform for processing and transport to shore.
Problem Well Analysis - Pumping Oil Wells
Authors: Kelm C.H.
Published: December 2007

Kelm, C.H., Member SPE-AIME, Amoco Production Co. Production Co.

This paper presents practical methods of recognizing and analyzing problem well symptoms. It also discusses the required data and its use, as well as presents a "well checklist" that assists the engineer in analyzing well performance. The objectives of well analysis are to maximize producing rates and recovery within allowable, economic and/or reservoir restraints. Based on experience gained from beam pumped oil wells in West Texas waterflood projects, well analysis as presented can be applied to oil wells produced by other means of lift and reservoir drive mechanisms.

Introduction

Maximizing pumping oil well rates and reserves within certain restraints have always been the objectives of the petroleum engineers. One of the obstacles that prevents achieving these objectives is problems that occur within the wells. These problems can be associated specifically with the reservoir, the wellbore and near wellbore area and mechanical aspects of the producing well. In this paper the primary concern is with the problems of the wellbore or near wellbore area and/or the mechanical condition of the well.

Symptom recognition and definition of the cause of a problem can best be accomplished through regular collection and analysis of individual well production data. Although many times production data must be supplemented with other data to completely review performance.

In shallow West Texas waterfloods, where beam units are the prevalent lift mechanism, it has been found that constant review of overall project and individual well performance by the production engineer results in wells being maintained in their optimum producing condition. These reviews are facilitated by the collection and proper display of at least monthly well test and fluid level data or pump off control device pump time on every producing oil well. pump time on every producing oil well. A "well checklist" as developed in this paper, helps the production engineer organize well performance and mechanical data necessary for well reviews. Once the data is organized, performance analysis becomes a matter of interpreting the data and comparing the well's performance or predicted performance to that of another. predicted performance to that of another.
Peraguage - A Permanent Surface Recording Downhole Pressure Monitor - Through a Tube
Authors: Weeks Steve G. , Farris Gerald F.
Published: December 2007

A permanent means of continuously monitoring downhole pressures without interruption of producing or injection operations, was first tested in Germany more than 25 years ago. This initial development plus subsequent modifications each require an electric cable to transmit a signal reflecting downhole pressures. A new tool has been introduced which does not utilize any downhole electronics or electrical conduit. This pressure transmission system, or Permagauge, consists of a 3/32 inch O.D. tube, attached to the outside of the production tubing, connecting a surface recorder to a downhole chamber in communication with the well fluids. Downhole pressures are determined by adding the recorded surface pressures to the calculated pressure exerted by the weight of an inert gas column in the small tube. A portable surface unit provides versus time as portable surface unit provides versus time as well as a digital display for continuous pressure monitoring. pressure monitoring. Since initial installation, more than 75 Permagauges have been run, including installations in a CO2 pilot project in Southeastern Mississippi. Discussed are a general description of previously available remote reading bottom-hole pressure gauges, a resume of all Permagauge installations, plus detailed experience with the Mississippi plus detailed experience with the Mississippi runs verifying the accuracy of the Permagauge to be equal to wireline pressure surveys.

Introduction

Bottom-hole pressure data are routine requirements for evaluation of production and reservoir pressure response may be especially helpful in evaluation and control of supplemental recovery projects. This might include producing, build-up and static surveys as determined by pressure recorders run on wireline. However, frequency and number of wells surveyed may be limited due to interruption of normal production routine, as well as expense. Presence of some artificial lift equipment will prevent running conventional pressure surveys. Furthermore, production pressure surveys. Furthermore, production of highly corrosive fluids, together with potential damage from wireline cutting where potential damage from wireline cutting where plastic-coated tubing is installed, can also plastic-coated tubing is installed, can also be a deterrent to obtaining useful pressure data.

Permanent installation of a downhole pressure detector provides a means of pressure detector provides a means of continuously recording pressures and may aid in adjustment of fluid movement within a reservoir.
Evaluating Formation Damage in Low Permeability Sandstone
Authors: Pence S.A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The massive gas formations in the Rockies, such as Mesaverde, will be among the sources of our future gas supplies. Effective stimulation treatments will be in larger volumes than the industry previously found economically feasible. Although higher gas prices make stimulating tight sands possible, the problem of selecting less damaging fracturing fluids remains. The effects of confining pressure, reported in the literature, have been confirmed in tight sandstone cores. These effects may make present test procedures for formation damage meaningless unless rigid test procedures are imposed in the laboratory. This paper describes equipment and techniques developed to evaluate damage caused in gas formation cores by candidate fracturing fluids.

Introduction

The massive gas formations in the Rocky Mountains such as the Pictured Cliffs, Mesaverde and Frontier will be among the sources of future United States gas supplies. Randolph has estimated recently that of 1,015 trillion cu ft of potential natural gas reserves, 600 tcf is presently noncommercial in the Green River, Piceance and Uinta basins. About half of this may someday be recovered by nuclear or by massive hydraulic fracturing.

The laboratory permeabilities, reported in the literature for cores from some of the above basins, did not agree with permeabilities derived from production tests in the field. Thomas and Ward have reported that in-situ permeability in very tight reservoirs is a permeability in very tight reservoirs is a strong function of water saturation and overburden or confining pressure. Unconfined Gasbuggy rock, for instance, had 10 to 20 times the permeability of its in-situ permeability. Similar effects have been reported earlier by Fatt and others.

Certainly these findings could have a pronounced effect on the accuracy and pronounced effect on the accuracy and reliability of laboratory measurements of permeability and perhaps, fluid-loss parameters used permeability and perhaps, fluid-loss parameters used when designing fracturing treatments. Since present methods of estimating formation-damage present methods of estimating formation-damage use permeabilities as their basis, a valid test procedure must take these findings into account. procedure must take these findings into account.

Formation-Damage Variables

An excellent presentation by Carney and Wieland discussed the evaluation of fracturing fluids for low-permeability gas formations. They classified formation damage due to migratory fines from the rock itself and due to liquid retention in the pores of the rock. Selection of the fracturing fluid to use in any particular formation is often done on the basis particular formation is often done on the basis of laboratory formation-damage tests.
Pressure-Transient Analysis of Perforated Slant and Horizontal Wells
Authors: Ozkan Erdal , Yildiz Turhan , Raghavan Rajagopal
Published: December 2007

This study investigates the transient pressure behavior of perforated slant and horizontal wells and discusses the implications of perforations on the analysis of pressure and derivative responses. The results presented are derived from a 3D analytical model. In this model, it is possible to consider nonuniform distribution of perforations and each perforation may have different penetration length and skin factor. It is shown that convergent flow into perforations significantly influences the early-time flow characteristics. In addition to discussing transient behavior, the effect of perforations on productivity is also discussed.
Wax Precipitation in Gas Condensate Mixtures
Authors: Nichita Dan Vladimir , Goual Lamia , Firoozabadi Abbas
Published: December 2007

Wax precipitation for gas-condensate fluids was studied in detail using a thermodynamic model. It was found out that the precipitated wax phase can exhibit retrograde phenomena similar to that in gas condensates. As a result of pressure decrease (at constant temperature) the amount of the precipitated wax may increase first, then decrease and increase again.

The effect of pressure on wax precipitation from gas condensates was also studied. It often shows an opposite effect in wax precipitation from liquids. However, the pressure effect is not universal.

The model used in this work accounts for both the Poynting correction term and the solid-state phase transitions. Incorporation of these effects reconfirms the suitability of multisolid phase for wax precipitation calculations (both the onset and the amount).
Natural Gas Supply Situation (September 1975)
Authors: DeLaMater Stephen T.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper briefly reviews the significance of the gas industry as an indispensable source of energy for each of the residential, commercial and industrial sectors. It discusses the nature of the energy/natural gas shortage and its causes. The basic reason for the shortage is almost universally conceded to be the misapplication of federal regulation of the wellhead price of gas, but impeding solutions to the problem are misconceptions as to the feasibility of alternatives. Specifically, there has been unwarranted reliance on conservation, overly optimistic expectations with respect to "exotics", and apparent bias, on the part of some government decision makers, toward "all electric". Also discussed are factors that will affect future trends in fuel usage, the importance and availability of natural gas supplementals, the economic impact of an extended severe gas shortage, the need for increased new gas exploration, and the case for deregulation, including its economic impact on the consumer. This paper concludes that there must be a national imperative for a continuity of our gaseous fuel supply.

SIGNIFICANCE OF THE GAS INDUSTRY

Natural gas remains the least understood of all of our energy sources. We became dependent upon it almost overnight after WW II because of its sudden abundance at low cost, and because of its premium qualities of cleanliness, versatility and efficiency.

Today people are frankly surprised when they finally come to understand the pervasive ross of its use. Natural gas and its related supplementals provide over 31 percent of the primary energy used in the United States; over primary energy used in the United States; over 41 percent of the nontransportation energy used; more primary energy than any other source produced domestically (41 percent gas, 30 produced domestically (41 percent gas, 30 percent oil, and 23 percent coal); 17 percent percent oil, and 23 percent coal); 17 percent of our national electric power generation; nearly 50 percent of all industrial energy; and 42 percent of the residential and commercial market. Natural gas heats 39.4 million homes and 56 percent of all dwellings. It is the largest single fuel source for the residential, commercial, and industrial markets.
New Through-Tubing Gravel Pack Techniques
Authors: Shurtz Glenn C. , Comeaux Bob G.
Published: December 2007

Production of formation sand continues to be a major operating problem for Production of formation sand continues to be a major operating problem for the petroleum industry, particularly in the geologically young and poorly consolidated reservoirs of the Gulf Coast area.

Remedial through-tubing gravel-pack installations have been greatly simplified through the use of specially designed setting tools and a highly viscous, cross-linked polymer, gravel-carrying fluid. Based on field data, this technique or design application has been highly successful. The term gravel or gravel packing herein is intended to mean any matter used as a packing material. packing material

Introduction

Recovery of oil and gas from poorly consolidated sand formations continues to be a major challenge to the petroleum industry. Sands is usually entrained in fluids produced from such formations, causing equipment erosion and surface handling problems. Often sufficient volumes of sand will enter the production string to completely block or severely restrict fluid flow, making production impossible or prohibitively expensive.

In reservoirs where sand production is a problem, economic production of oil and gas cannot be achieved without some mechanical method of sand control (gravel pack, prepack or chemical consolidation). When a formation is known to produce sand, some measure of sand control should be included in the initial completion. However, in many cases, formation characteristics are not known and wells are completed without sand control. Sometimes these wells produce for months or even years before sand production becomes a problem. Consequently, hundreds of wells in the Gulf production becomes a problem. Consequently, hundreds of wells in the Gulf Coast area are currently sanded up and off production. Many will remain off because of the prohibitively high cost of a major rig workover to pull the production tubing and install sand control. This is not a new problem, and for years the industry has attempted to perfect through-tubing sand-control techniques as an economic means of returning these wells to production. Some limited degree of success was obtained with both production. Some limited degree of success was obtained with both through-tubing chemical consolidation and gravel-packing methods. Because of the high failure rate on completion and the limited life associated with chemical consolidation processes, a harder look was again taken at through-tubing gravel packing.
All Purpose Cement-Mud Spacer
Authors: Beirute Robert M.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in Houston, Tx., Jan 29–30, 1976. 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 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.

This paper deals with the problem of formation damage generated by high pressure differentials between annulus pressure differentials between annulus and formation during cementing. Specifically, the elimination of viscous cement-mud mixtures by the usage of a water external (oil in water), temperature stable emulsion spacer is presented. presented. Careful attention is given to the preparation of the casing and well bore preparation of the casing and well bore surfaces by the spacer, prior to cementing. Lab and field results clearly show that cement bonds best to a waterwet surface created by the water external spacer.

The effect of contamination on fluid loss control of well fluids is presented. Other tests indicate that cement strength is less affected when contaminated with a water external emulsion spacer than when contaminated with oil base fluids.

Introduction

Mud displacement mechanisms, spacers and problems created by the contamination of cement by drilling muds have been discussed previously in the literature. However, in this paper we take a closer look at spacers from the point of view of formation damage control and cement bonding.

Formation damage can be caused by drilling fluids during drilling operations, but further formation damage can occur during cementing operations. The fluids and solids lost from slurries can cause damage by entering the formation and reducing its permeability.

The amount of fluid lost from a cement slurry into a formation depends on several factors, including the pressure differentials occuring during pressure differentials occuring during cementing. The higher the pressure differential into the formation, the more fluid will be lost to the formation.
A Review of Hydroxy-Aluminum Treatments
Authors: Haskin C.A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in Houston, Tx., Jan 29–30, 1976. 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 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 this paper, may be considered for publication in one of the two SPE magazines.

Hydroxy-aluminum chemical (OH-Al) has been used in hundreds of wells to sustain production by stabilizing clays that cause permeability damage and well sanding. Commonly used in conjunction with other well stimulation processes OH-AL has prolonged the stimulated production response and extended the life of producing equipment.

Among the many successful treatments have been some failures, however, the number of failures have been small relative to the number of successful OH-AL treatments that have been done. Mechanically damaged wells, downhole placement problems, poor job design, and failure to consider the limitations of the OH-AL chemical have been the primary causes of failure among most of the unsuccessful treatments that have been reported.

Correct well diagnosis and good job design can significantly reduce the risk of job failure regardless of the type of well treatment involved. Understanding how OH-AL interacts with the formation clay minerals helps determine when and where the chemical might be used most effectively. Recognizing the effect of chemical incompatibility, temperature, and OH-Al concentration on treatment results is essential for optimum job design.

Introduction

Several hundred wells in the industry have been treated with clay stabilizing hydroxy-aluminum (OH-Al) chemical since the technology was introduced in 1971. Figure 1 shows the number of wells treated with OH-Al chemical through 1974. The majority of treatments have been done in oil wells, but gas wells and water injection and source wells have also been successfully treated. Most OH-AL treatments have been done for (1) sand stabilization, (2) sustaining production following acid stimulation, and (3) stabilizing clays ahead of steam stimulation and water injection.
Application of SSOR to Three-Dimensional Reservoir Problems
Authors: Wattenbarger R.A. , Thurnau D.H.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A relaxation method called Slice Successive Overrelaxation has been developed for the solution of matrix problems occurring in three-dimensional reservoir simulation. The SSOR technique represents a significant improvement over previously used techniques and is considered to be a general method.

The mathematics of SSOR is a straight-forward extension of block SOR techniques in which the submatrix, or block, corresponds to a vertical plane (slice) through the reservoir. This technique has become practical by the application of a reordering practical by the application of a reordering scheme to the direct solution of each submatrix. On iterations subsequent to the first, the forward elimination on submatrices is not required, making succesive iteratons comparable to LSOR in speed. The Watts correction method is applied in its generalized manner similar to LSOR and dramatically enhances the speed of convergence.

Test results are shown for various reservoir problems. The method is shown to be particularly advantageous in a typical three-dimensional problem where vertical permeability barriers exist in portions of the permeability barriers exist in portions of the reservoir and high vertical transmissibilities occur elsewhere. It is demonstrated that the convergence rate of applying SSOR to a three-dimensional problem is essentially the same as the convergence rate of applying LSOR to the two-dimensional projection of the same problem. A method is presented which can be used to estimate the computer time required for an SSOR solution.

Introduction

One of the persistent problems in reservoir simulation is that of solving the matrix problem which arises from the "pressure problem which arises from the "pressure equation." Over the years, a number of methods have been developed and utilized with success for various types of problems.

For most reservoir simulation problems, we find that the solution of the matrix problems, we find that the solution of the matrix problem is very efficient and represents problem is very efficient and represents only a minor part of the cost of a reservoir simulation computer run. On other problems, however, the solution method can problems, however, the solution method can become sufficiently slow so that the matrix problem dominates the computer cost. problem dominates the computer cost.