bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.

Abstract
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.

Abstract
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.

Abstract
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.

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.