bluuebunny/crossref_metadata_2025 huggingface dataset:
Electrical Logging Responses Explained By Conventional Core Data
Authors: Anderson J.C.
Published: December 2007

Anderson, J.C., Pan American Petroleum Corporation, Lake Charles, La. Junior Member AIME

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.

The importance of open hole electrical well logs and their proper interpretation cannot be over-emphasized. A great number of the decisions made in drilling, development, and production operations are made on the strength of what electrical well logs tell us of subsurface conditions. Thereby log interpretation work can have a very real effect on the economics of a given venture. Thus it is unfortunate that many times log responses suggestive of non-productivity or low productivity can be recorded in reservoirs capable of hydrocarbon production at high capacity.

In 1960 an extensive three well conventional coring program was undertaken by Pan American Petroleum Corporation in the Bastian Bay Field of Plaquemines Parish in South Louisiana. The purpose of this program was to obtain reservoir data for use in gas reserve estimation. Over two thousand feet of conventional core was obtained from the Upper Miocene gas reservoirs found at Bastian Bay. The volume of porosity, permeability, capillary pressure and descriptive data available from this program is seldom available in the Gulf Coast area and therefore it provided an excellent opportunity to study the various logging responses experienced. A preliminary comparison of the core date with the Induction-Electrical logs and Micrologs obtained has been made and the results are presented herein. The study shows that log responses most often associated with reservoirs which are non-productive of hydrocarbons or that are of low productivity, can be recorded in reservoirs which are productive of hydrocarbons with high productivity.
Application of Material Balance Techniques in Matching and Predicting Performance of the Heterogeneous Multilayer Hassi Messaoud Field
Authors: Miesch E.P. , Khelil Chakib
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Material balance techniques were used to calculate the active oil represented by the build-up pressures of the individual wells in the heterogeneous multi-layer Hassi Messaoud field. The technique of Amyx, Bass, Whiting, Havlena, and Odeh were used.

This application improved the history matching phase of a reservoir simulation project that was being conducted on the field. project that was being conducted on the field. The material balance results were used as a criteria for selecting a combination of "grids" to represent each well in the mathematical model that in turn would be used to obtain volumetric average pressures for comparison with the measured data.

The study indicated areas of the Hassi Messaoud field that were obtaining vertical and horizontal oil influx. Subsequent drilling has concerned the location of this additional oil in many parts of the field.

Introduction

This study was made in conjunction with a reservoir simulation study that was recently conducted on Algeria's largest oil field, the heterogeneous, multi-layer Hassi Messoud. The field was discovered in December 1957 and is located in the Algerian Sahara Desert about 375 miles southeast of Algiers as shown in Figure 1. At this time of this study, 1971, the oil productive area was approximately 23,000 acres. Production is from the Cambrian Ri-Ra zone. The original reservoir pressure was approximately 6855 psi and the maximum saturation pressure was approximately 2900 psi. It is at a depth of about 10,500 feet subsea, and it has approximately 245 feet of net pay with an average porosity of eight percent. The average permeability to air of percent. The average permeability to air of 41.7 md was obtained by averaging the values for all samples with kair greater than 0.1 md. Reservoir rock and fluid properties are shown in Tables I and II respectively.

The Ri-Ra formation is underlain by the R2-R3, which is also oil bearing. The R2-R3 member was penetrated by only a few of the wells because of the lack of commercial production from this member. Consequently, the available data for the zone are limited.
Bidding and Production Relationships for Federal OCS Leases: Statistical Studies of Wildcat Leases, Gulf of Mexico, 1962, and Prior Sales
Authors: Lohrenz John , Oden Hillary A.
Published: December 2007

The relationships between bids received on wildcat leases issued on federal OCS lands in the Gulf of Mexico from 1954 through 1962 and subsequent drilling on, production from, and relinquishment of these leases were studied. The results provided quantitative answers to questions regarding bidding as prescribed by current laws and regulations. Perhaps the most notable result is the finding that, while leases receiving the most and highest bids tend, on the average, to produce more revenue, such leases tend to produce less revenue per dollar of bonus spent on the lease.

Introduction

The laws and regulations pertaining to the issuance of federal leases on the outer continental shelf (OCS) using a sealed-bonus bidding system are under continual scrutiny by many segments of the government, business and industry, and the public as individuals interest groups. Many questions are ask about the relationships between what is bid for a lease and what happens subsequently on the lease. Is it drilled? Is it productive? If so, how much and when?

During 1972, over $2 billion were spent in buying OCS leases; over $7 billion were offered in the bidding process. Even if there were no cogent energy-supply issues, the money involved makes the questions-cogent and timely.

These questions are the impetus for studies to analyze the relationships between bids on leases and their subsequent drilling, production and relinquishment. production and relinquishment. The results reported are for the 788 wildcat federal leases issued on the OCS offshore Texas and Louisiana between 1954 and 1962. Thus every lease included had a history of more than 8 years through 1970. All bids, the annual production, the annual revenue data and, if production, the annual revenue data and, if relinquished, the year of relinquishment for each of the 788 leases through 1970 were included in a computerized data base for these studies.

The 788 leases were divided into three groups by date of sale as follows:the 230 leases issued as a result of the Oct. 13, 1954, Nov. 9, 1954, and July 12, 1955 sales,the 147 leases issued as a result of the Feb. 24, 1960, sale andthe 411 leases issued as a result of the March 13, 1962, and March 16, 1962, sales.

For these studies, a lease was considered relinquished only if it was wholly relinquished.
Progress Report On Acoustic Amplitude Logging For Formation Evaluation
Authors: Walker Terry
Published: December 2007

Publication Rights Reserved

This paper is to be presented at the 37th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in Los Angeles, California, October 7–10, 1962, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations unless the paper is specifically released to the press by the Society Publications Committee Chairman or the Executive Secretary on his behalf. Such abstract should contain appropriate, conspicuous acknowledgment. Publication elsewhere after publication in Journal of Petroleum Technology is granted on request, providing proper credit is given that publication and the original presentation of the paper.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office; it will be presented at the above meeting with the paper and considered for publication in Journal of Petroleum Technology.

Examples of acoustic amplitude logs have shown the application in obtaining more efficient well completions by locating any natural fracturing and confining any necessary well treatment to that interval. Since early 1961 logs have been run in practically all areas and all types of formations. Investigation into the theory of acoustic transmission of all arrivals through various formations indicate the possibility of a usable correlation of signal amplitude with matrix permeability. Although only a limited amount of field data is available at present, indications are that a usable matrix permeability anomaly does exist.

The matrix permeability effect and other possible useful information from the acoustic signal are being studied by different recordings of the full receiver signal preferably on cored wells to allow determination of the most useful information and the best means for recording.

Introduction

In early 1961 the Fracture Finder was introduced commercially to the industry, making use of the acoustic transmission of the formation to locate optimum completion intervals. As described in a previous paper the signal amplitude is reduced because of the large reflection of energy at density interfaces resulting from naturally existing formation fractures. Test well data was shown where the signal was reduced 23 per cent by a horizontal interface between machined limestone blocks. Although it is probable that this reduction will depend upon the fracture width and area of bearing surfaces across the fracture, the degree of reduction can be used as an indication of the extent of fracturing.

This log has since been run in practically all areas and has materially aided in selecting optimum completion intervals. In a number of formations the interval to be perforated can be reduced and any required treatment confined to that interval most susceptible to such well treatment.
A Technique For Assessing And Improving The Quality Of Reservoir Parameter Estimates Used In Numerical Simulators
Authors: Breit V.S. , Bishop K.A. , Green D.W. , Trompeter E.E.
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The sophistication of the current applications of numerical reservoir simulators places great emphasis on the quality of the parameters used therein. The accuracy of parameters, which are often determined by history matching procedures, significantly affects the extent of the applications of a simulator. This paper applies certain useful concepts of sensitivity analysis from formal optimization theory to the assessment of the quality of the estimates of reservoir parameters used in reservoir simulators.

The assessment is accomplished by determining the sensitivity of an objective function this case the time integral of the squared error in simulator performance) to the value of reservoir parameters performance) to the value of reservoir parameters used in the simulator. The determination employs a truncated Taylor series expansion of the objective function about a point specified by the current estimate of the reservoir parameters. The partial derivative terms of the expansion are calculated from the finite difference approximation to the differential equations used in the simulator, differentiated with respect to the current estimate of the reservoir parameters. The calculation of the terms in the expansion leads to a complete accounting of all the sources of error in the simulator's performance provided that the true reservoir performance provided that the true reservoir parameters are known. In practice, where the true parameters are known. In practice, where the true values of parameters are not known, the technique can be used in two ways:To provide a complete accounting of the effect of small parameter perturbation.To generate improved estimates of the true parameter values.

The method is applied to two reservoir simulators:a radial, slightly compressible single-phase model, anda dimensional slightly compressible, single-phase model.

In each case, the model is used to obtain a better estimate of reservoir parameters and a spatial distribution of the sources of the error in performance prediction. performance prediction.
Experience with Production Systems Analyses
Authors: O'Reilly W.M. , Clement J.P.
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Production systems analyses are specialized tools to identify potential conditions which could cause unsafe operating conditions or damage the environment. Individual techniques range from a relatively simple identification of vulnerable points (qualitative technique) to a fairly sophisticated evaluation (quantitative technique) requiring failure rate data on each component. This paper reviews Exxon's experience in using qualitative techniques on 6 production facilities and a quantitative production facilities and a quantitative technique on 4 facilities. Our experience indicates that qualitative-type techniques are more applicable than quantitative-type techniques for petroleum production systems.

Introduction

Following the Santa Barbara oil spill in 1969, increasing public concern about environmental protection encouraged governmental agencies to intensify efforts to reduce the possibility of pollution from oil spills. Rigorous testing and reporting schedules for key equipment components were initiated. Other formalized reports are also required to insure that well-designed facilities are diligently operated for safety and to prevent environmental damage. These prevent environmental damage. These reports carry a variety of names such as Environmental Impact Statement, Systems Analysis, and Spill Prevention Control and Countermeasures Plan. By whatever name, the objective of the work is to identify conditions that could result in problems and to consider measures to problems and to consider measures to prevent these conditions from developing prevent these conditions from developing The USGS in the fall of 1971 contracted a NASA team to perform a feasibility study to determine if NASA-developed procedures for quality control and hazard analysis would be applicable in oil and gas offshore operations. This aerospace group brought with them some terminology, such as "Hazard Analysis" which is not publicly well understood. In a recent publicly well understood. In a recent report the USGS designated this work activity "Systems Analysis" which we concur is more descriptive of the reliability studies which have been made in production operations.
Bit Performance
Authors: Vitter A.L.
Published: December 2007

Models for Bearing Wear, Teeth Wear and Penetration Rate of bits have been developed Penetration Rate of bits have been developed which give reasonably good correlations on Louisiana Gulf Coast and Offshore data sets.

In addition to the usual significant variables reported in the literature, bit hydraulic horsepower and bit mechanical horsepower have both been found to be significant variables not only in the Penetration Rate models but also in the Penetration Rate models but also in the Bearing Wear and Teeth Wear models.

A Torque Oscillation Meter (TOM) has been developed and three prototypes have been successfully used for the last two years in the real time monitoring of bit condition and other downhole conditions to obtain maximum economic bit life, and further enhance bit performance. performance

Introduction

The need to incorporate bit performance into optimum well planning has grown in importance as the industry has ventured into more expensive areas. The environmental effect of mud systems on bit performance has been difficult to appraise but the advent of the sealed bearing bit has greatly reduced the mud system as a significant variable except for its weight and viscosity effects, which are more readily characterized and accounted for.

BIT BANK

In order to efficiently gather, correlate and use bit performance a data bank was initiated in September, 1972. About 100 bits per month are deposited in this data bank and this paper reports on the first 9 months of operation. Utilization of the data bank in predicting bit performance for optimum well planning is just performance for optimum well planning is just commencing. Six data sets have enough bits to report on preliminary correlation results.

Deposits, retrievals and correlations are done from each of three Louisiana operating offices, although at this early stage of exploratory model building on bit performance, the correlation work has been largely done in New Orleans. The bank is resident in San Francisco and readily accessible from all four locations.

A continuing effort is being made to obtain reliable data. Bit grading needs to be done consistently according to prescribed procedures. Bearing grading is the most difficult of the gradings. At the suggestion of one of the major bit manufacturers a quantitative measure of bearing wear is accomplished with a jig and dial micrometer to measure the lateral movement of the bit cone as it is rocked back and forth on its shank. These are standard machine shop items that are readily available with a magnetic clamp to hold it firmly on the bit leg with the loosest cone. They are kept aboard the rig to grade the bit as soon as it is pulled from the hole.
From Chaos To Conformity
Authors: Porter Al.
Published: December 2007

A history of the petroleum industry in the United States might be called "From Chaos to Conformity," and by history I mean past, present and future. We who are connected in anyway with this industry or with the conservation of oil and natural gas must readily admit that, although much progress has been made toward maturity, we still exhibit an adeptness at fumbling the ball. An objective examination of our century of existence made in sober reflection, brings to light of flashing brilliance and even statemanship. It also uncovers substantial periods.

The industry has had to overcome many obstacles, not all of which were self made, (and I hope we can take a little comfort from that fact). May be it is possible to excuse some of our early practices when we think of them in the light of contemporary thinking. One of Col. Drake's favorite stories was about the local minister who met him on the streets of Titusville and severely reprimanded him for taking oil from the ground on the theory that it was placed there by our Creator to supply fuel for the fires of hell, and that by taking it from the ground he was thwarting the will of the Almighty and allowing sinners to go unpunished.
Creative Task Force Attack on Profit Loss Due to Formation Damage
Authors: Allen T.O.
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Many currently accepted drilling and producing practices cause appreciable formation damage. Major changes in field operations are required to prevent or alleviate this damage.

In planning a coordinated attack on formation damage, the Creative Task Force offers a proved approach to bring about desired results. Case histories of major task force projects relating to formation damage are presented. presented. Because of the potential economic impact on the oil and gas business, an all out attack on formation damage should be solidly supported by Management of the various oil and gas producers, service companies, drilling producers, service companies, drilling contractors, and workover contractors on a worldwide basis.

Introduction

Formation damage causes significant loss of both short and long term profits in the Petroleum Industry, and probable loss of millions of barrels of recoverable oil and billions of cubic feet of gas.

Many currently accepted drilling and producing practices introduced during the era of abundant reserves and excess producing capacity in the U.S. cause appreciable formation damage. major changes in field practices are required to prevent or alleviate this damage. Needed changes have probably been delayed for some 25 years because of poor producing economics related in a large degree to low prices for oil and gas. However, there also appears to be the lack of appreciation of the magnitude and widespread extent of the damage problem.
Our Petroleum Reservoirs Deserve Better Care
Authors: Hurst R.E.
Published: December 2007

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

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Surplus petroleum production for our domestic industry is a thing of the past. Finding of additional reserves is both difficult and expensive. If we expect to maintain any resemblance of an efficient production unit, we must reorient management thinking, train our people, and provide the atmosphere in which our well operations can proceed with as high a degree of care as we have demanded from the medical profession. Our goals can no longer emphasize cheap energy today. We must emphasize a longterm, adequate supply at an efficient price. Billions of barrels of oil remain locked in place because of our failure to carefully apply all the knowledge available to us. This paper will point out a few of the past mistakes and offer solutions from available technology. Hopefully, such examples will stimulate our efforts to discover and apply the "loving" care our reservoirs deserve.

Introduction

Formation damage from external forces is probably the greatest single cause of less than maximum recovery of petroleum. Past abundance of petroleum, with its arbitrary restricted production and relatively low value created an atmosphere where formation damage was either not recognized or was tolerated to achieve minimum well costs. Formation damage is a management problem. Technological and human resources are available to prevent or minimize damage. Management must redirect these resources in balance with the economic resource if we are to make progress. Formation damage most often occurs from physical destruction of the natural reservoir integrity or adverse chemical reactions with reservoir rock and entrapped petroleum.

DESTRUCTION OF RESERVOIR INTEGRITY

This type of formation damage most often occurs from destruction of reservoir barriers through hydraulic action in well drilling and completion or by production flow practices from poorly consolidated sands. Rapid decision requirements placed on the drilling and completion engineer to maintain hole stability or to control blowouts frequently prevents precise application of available technology in extreme wildcat conditions.
A Case History of Polymer Waterflooding Brelum Field Unit
Authors: Rowalt R.J.
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Three and one-half years of polymer waterflooding in the Brelum Field Unit have provided sufficient data to evaluate the project's performance. Addition of polymer will increase the ultimate recovery of the flood by 250,000 barrels over a conventional waterflood. Increased recovery is attributed to improved reservoir conformance. The predicted producing rate was not reached predicted producing rate was not reached because of lower than anticipated injection rates. Polymer flooding has resulted in a stabilized producing rate and low water-oil ratios for the past three and one-half years. General polymer breakthrough has not occurred polymer breakthrough has not occurred to date. Operational problems with the polymer flood have been minor and are polymer flood have been minor and are generally related to reduced injectivity.

Introduction

A case history of three and one-half years of polymer waterflooding the Lower Government Wells Reservoir in the Brelum Field is reviewed. The polymer flood utilizes eight producing wells and 12 injection wells in a staggered line drive pattern. The areal extent of the total pattern. The areal extent of the total reservoir is 427 acres containing 4275 productive acre-feet with an initial oil productive acre-feet with an initial oil in place estimated to be 5.1 million barrels. The Unit encompasses 264.5 acres containing 2400 productive acre-feet with an original hydrocarbon volume of 2.9 million barrels in place.

RESERVOIR CHARACTERISTICS

I. GEOLOGY

The Brelum structure is a combination monoclinal fault and stratigraphic trap. The trap is bounded by an oil-water contact on the northeast and by pinchouts on the south and west. (Refer pinchouts on the south and west. (Refer to Figure 1.)

The Lower Government Wells Sand, which is the producing horizon, occurs at an average depth of 1950 feet and is a member of the Jackson Group of Eocene Age.
Production Exploitation in CPC Fields
Authors: Cecil Allen W.
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 study conducted by Exxon Company, U.S.A. is described in which an operations/engineering team approach was used to establish surveillance activities and responsibilities for improving benefits from computer production control installations. These activities include identification of problem wells and lease production problems, allowable management, monitoring measurement accuracy and general system surveillance. The results of the study show that capture of benefits can be improved. An operations/engineering organization is outlined for surveillance on a continuing basis.

Introduction

Exxon Company, U.S.A. has successfully implemented computer production control (CPC) in four of its five operating Divisions. The CPC systems in each Division were developed based on the following three fundamental guidelines:Identical computer hardware and software would be used at each Division operating level.CPC information would comprise a single data source for operations, engineering, and accounting functions in the Company.Field operating personnel would control the system and be an essential element in the data reliability activities.

After each individual field CPC installation is complete, the major benefits of CPC lie in using automated information to increase production and improve operating efficiency. However, all benefits do not just automatically accure. In fact, some disorganization can develop among functional groups about specific surveillance activities and responsibilities. The results may be duplication of surveillance effort, overlooked surveillance activities and missed opportunities. To ensure achieving a high percentage of benefits from CPC, a concerted effort should be made to organize and establish surveillance responsibilities at the field and staff levels.

Presented in this paper are the results Presented in this paper are the results of a study conducted in Exxon Company, U.S.A.'s East Texas Division (located in Houston, Texas) to establish an operations/ engineering team approach to surveillance of CPC information. The East Texas Division CPC system uses an IBM 1800 computer and has been in various stages of implementation since 1969. This system now serves approximately 2500 wells in twelve fields. Five of these fields located in one of the districts within the East Texas Division were involved in the surveillance study described here.
Multi-Phase Flow Measurement by Orifice Meter
Authors: Wichert Edward
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 simple method is developed for calculating the gas flow or the total equivalent hydrocarbon vapour flow fro multi-phase orifice meter measurements in field gathering installations. In addition to the usual parameters required for gas and liquid flow calculations, the hydrocarbon liquid/gas ratio and the water/gas ratio have to be known. It is shown that the accuracy of the results is quite insensitive to the accuracy of the liquid/gas ratios, and therefore the reliability of the multi-phase measurement is not adversely affected when actual liquid/gas ratios vary from assumed values. Results of several field tests are presented, and some previous literature presented, and some previous literature articles on this topic are reviewed.

Introduction

The production of hydrocarbons from high pressure gas-condensate reservoirs results in mixed-phase flow streams of gas, condensate and water from the wells. Such streams are normally piped through a common gathering system to a main gas processing plant for treatment. It is desirable for plant for treatment. It is desirable for reservoir information, or a requirement by a regulating agency, to measure the flow from each individual well prior to commingling of the flow streams in the gathering system. one way of measuring the production is to continuously separate the gas, condensate and water phases at each lease and measure the phases individually. After measurement, the flows can be recombined for piping to the plant. This approach is very costly in capital investment and equipment operation. A large cost saving can be achieved by metering the mixed-phase streams at the leases. A simple method is outlined herein for calculating the gas flow rate or the total hydrocarbon well effluent rate on the basis of multi-phase flow measurement by orifice meter.

MULTI-PHASE FLOW OCCURRENCE

The simultaneous flow of gas, condensate and water from a wet gas reservoir is a common occurrence. At the high pressure and temperature in the reservoir, the hydrocarbon mixture usually exists in the vapour phase. With production to surface, the pressure and temperature are lowered, and a two-phase hydrocarbon mixture will result in cases where the mixture is rich in the pentanes and heavier fractions. Water will also be present, either due to condensation or free present, either due to condensation or free water production.
Understanding The Present day In-Situ State of Stress in the Cusiana Field - Colombia
Authors: Charlez P.A. , Bathellier E. , Tan C. , Francois O.
Published: December 2007

Compressional tectonics in the Eastern Cordillera foothills are investigated using a large strain, two-dimensional finite clement method. The main purpose is to calculate the stress regimes within the Cusiana field and to compare the results with field data.

In the foothills, the NW-SE tectonic push is clearly confirmed by borehole breakouts. The present-day state of stress in the Cusiana field, is investigated through a footwall-hanging wall model with a detachment/ramp thrust fault. The tectonic push was simulated by applying horizontal displacement to the vertical boundary of the model. Simulations with both elastic and elastoplastic rheologies were performed.

To obtain a realistic horizontal stress gradient (in the range of 1.25 to 1.5 psi/fi) at depth, the stiffness of the hanging wall block has to be sufficiently low to accomodate the thrust geometry. With a perfectly sliding fault (zero friction), the tectonic push localizes the plastic deformation into a shear band which can be interpreted as the backthrust observed on the seismic section. Moreover, in the vicinity of the Cusiana thrust, the major principal stress rotates. This rotation is in good agreement with orientation found by core DSCA measurements.

P. 41
Stress Measurements for Sand Control
Authors: Desroches J. , Woods T.E.
Published: December 2007

Production of sand from a reservoir is a well known problem in the oil industry. Classically, it is solved by a gravel-pack or frac-and-pack type of completion. This approach, although resolving the sand production problem, has the important drawback of severely reducing the output of the completed well. Recently, two types of completions have been proposed for sanding prone reservoirs: slotted liners for horizontal wellbores and hydraulic fracturing without gravel packing in vertical wellbores. These completions have a less negative impact on reservoir production, but require high quality data acquisition to complete successfully. This paper focuses on how a combination of sonic measurements and stress tests carried out with the micro-hydraulic fracturing technique enabled the design of a successful hydraulic fracturing treatment for sand control offshore California.

Hydraulic fracturing specialists believe that a hydraulic fracture alone can successfully perform sand control if one has proper knowledge of the stresses acting over the zone of interest. The direction of the maximum principal stress is needed to ensure that all perforations are connected to the hydraulic fracture and therefore protected against sand production. Magnitudes of the minimum principal stress are needed for the proper design of the hydraulic fracturing job and, in particular, to ensure proper placement of the proppant which will stop the produced sand from reaching the wellbore.

Such an approach was successfully applied to a sanding- prone turbidite sand-shale reservoir. Critical knowledge of the stresses was acquired by first determining the azimuth of the preferred fracture plane from anisotropy processing of the sonic logs. This direction was validated from local knowledge of the active fault system. It is recognized that stress magnitudes are best measured with the micro-hydraulic fracturing technique. Thus, a special cased hole program was designed to measure the magnitude of the minimum principal stress with a wireline testing tool. Measurements were obtained in the two reservoir sands and three bounding shale layers. These measurements were then used to calibrate a stress log obtained with the processing of a sonic log. This provided a profile of minimum stress magnitudes along the zone of interest.

Analysis of the micro-hydraulic fracturing tests showed very little stress contrast existed between the reservoir rock and the bounding layers. This gave the client an option to design a single hydraulic fracturing treatment for the two layers, more efficient that the two separate treatments initially proposed. The interpretation also confirmed from a hydraulic fracturing standpoint that the azimuth derived from acoustic anisotropy was indeed that of the preferred fracturing plane. This allowed the client to orient the perforations with confidence.

The unique combination of measurements described in this paper enabled the client to design and successfully carry out a hydraulic fracturing treatment for sand control.

P. 219
Compaction Study for Shearwater Field
Authors: Kenter C.J. , Blanton T.L. , Schreppers G.M.A. , Baaijens M.N. , Ramos G.G.
Published: December 2007

In order to get a realistic prediction of the in situ stress evolution, compaction and subsidence of the HP/MT Shearwater field, full 3-D finite element calculations were made with the program DIANA. An interface was made to generate 3-D meshes directly from seismic files, which led to a most realistic representation of the actual geometry. An extended and modified Cam Clay model was used with and without a Duvaut-Lions creep extension to describe the observed test behaviour. Detailed calculations were made of cross sections, including main faults, secondary fault systems, slip layers and wells. It was found that stress arching was very significant in the Shearwater field geometry and led to a reduction of the compaction strains within the reservoir till below the critical values. However, the stress arching also reduces the total stresses in shales, faults and slip layers in the rock directly abeve it. Assuming that the high initial pore pressure is preserved in the overburden. this may lead to very low normal effective stresses and relatively high shear stresses, and as a consequence to a reactivation of faults and slip layers at the end of field life. It was found that only secondary faults close to the main fault will be reactivated and that the slip in activated slip layers is minimal above the crest of the reservoir. Therefore a drilling window could be identified that will minimise the risk of damage to the completion. Further, zero effective stress or flill liquefaction of the overburden shales close to the reservoir was identified as a realistic problem in case of strong stress arching and high pore pressures; however because of the high strength of the shales it did not appear to be a problem in Shearwater.

P. 53
Advanced Sand Prediction in a User Friendly Wrapping
Authors: Kjorholt H. , Joranson H. , Markestad P. , Raaen A.M. , Viken R.
Published: December 2007

This paper describes Statoil's sand prediction methodology. The methodology includes a set of procedures and tools put together in a system that allows for efficient prediction. The core element is a menu-based Finite Element (FE) simulator utilizing Internet technology. The menu allows the user to define the problem and start an advanced sand prediction simulation with a minimum of effort and computer skill. The simulation itself is based on flexible, predefined Finite Element models with built-in quality control. The philosophy is to offer a computerized system that also makes state-of-the-art sand prediction possible for those not familiar with highly specialized software. The system also provides more or less standardized routines for characterizing the mechanical properties of the formation and for determining the rock stress state. The flexibility and simplicity of the system make it a powerful tool in optimizing completion design.

P. 133
Control Of Water Mobility Using Polymers and Multivalent Cations
Authors: Needham R.B. , Threlkeld C.B. , Gall J.W.
Published: December 2007

A newly developed process using a combination of water-soluble polymers and multivalent cations to reduce water mobility has been tested in the laboratory. The process treats the porous media with a sequence of three slugs, porous media with a sequence of three slugs, the first and third being polymer solutions and the second being a solution of a selected multivalent cation. Calcium, magnesium, and aluminum cations have been used with partially hydrolyzed polyacrylamides or copolymers of acrylamide in laboratory flow tests. For example, treatments of Repetto sandstone cores having brine permeabilities of 200 to 400 md with a polymer solution resulted in a residual resistance factor to brine of about 3; whereas, residual resistance factors of 16 to 18 were obtained by using either calcium or aluminum cations in the three-slug combination treatment with the same polymer.

Based on laboratory evidence that polymer concentrations of 250 ppm can produce residual resistance factors in excess of 10 in porous media having brine permeabilities greater than 1 darcy, applications are evident in polymer flooding as well as in the high concentration-low volume treatment of oil-producing and water injection wells. These processes are being field tested in the treatment of producing wells and water injection wells to reduce water mobility and increase oil-producing rates.

Introduction

The action of polymers in porous media to reduce the water mobility has been extensively studied and, in general, is attributed to the increased viscosity of the polymer solution and to a reduction in permeability (residual resistance effect) to water of the porous media. For successful operations, the relative importance of these two methods of controlling mobility largely depends upon the application. In polymer flooding both methods of reducing the water mobility are important, with the permeability reduction effect probably being more permeability reduction effect probably being more significant where light oils and high variations in permeability are present. In the small volume treatment of water-injection wells to improve injection profiles and in treatment of production wells to reduce water-oil ratios, the production wells to reduce water-oil ratios, the permeability reduction effect is essential and permeability reduction effect is essential and the viscosity effect negligible. Although the various roles of polymer treatments are not clearly delineated for use with chemical flooding, the permeability reduction effect will perhaps be of dominant importance for perhaps be of dominant importance for pretreatment of reservoirs to achieve more uniform pretreatment of reservoirs to achieve more uniform injection of the chemical slug. By comparison, the viscosity effect is probably important in the slug proper, and both effects for use as a mobility buffer behind the chemical slug.
The Behavior of Polymers in Porous Media
Authors: Hill H.J. , Brew J.R. , Claridge E.L. , Hite J.R. , Pope G.A.
Published: December 2007

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., April 22–24, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL 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.

A partially hydrolyzed polyacrylamide and a biopolysaccharide are being investigated for use as mobility control agents in water flooding and in chemical flooding. Both polymers have functioned satisfactorily in some of our laboratory experiments and unsatisfactorily in others.

The polyacrylamide has given adequate mobility control in moderate permeability rocks when it is injected under conditions which minimize shear degradation. In bead pack flow experiments, we found that degradation occurs at shear rates of about 1000 sec-1. The polysaccharide solution was only slightly degraded by exposure to shear rates of about 30,000 sec-1. These observations, if applicable to field injection situations, limit injection rates severely in wells with restricted entry completions.

Mobility control with the polyacrylamide results from an increase in fluid viscosity and a reduction in permeability. The viscosity effect can be measured in permeability. The viscosity effect can be measured in laboratory viscometers but the permeability reduction must be determined from a series of core floods. As the polysaccharide functions only to increase fluid viscosity, estimation of mobility control for a given system is simplified. Viscosity of fluids containing either polymer can be reduced by shear degradation and, in the case of the polyacrylamide permeability reduction for a given fluid-core system can be severely lowered by shear degradation of the polymer.

The polysaccharide solutions compared with polyacrylamide solutions are less sensitive to shear polyacrylamide solutions are less sensitive to shear degradation, less sensitive to viscosity reduction by increasing salt concentration and are amenable to the use of simplified mobility design procedures.