bluuebunny/crossref_metadata_2025_split huggingface dataset:
Secondary Recovery by Butane Injection in San Pedro Block D
Authors: Moscrip Robert 
Published: December 2007

Abstract
A secondary recovery project involving butane injection followed by injected gas has been in progress in San Pedro Block D for six years. Data are presented covering both the primary and secondary phases of the depletion history. A discussion of the field operation is also presented.
Results or this field test indicate that substantial increases in oil recovery can be obtained by this secondary recovery process and that essentially all or the injected butane can be recovered with the produced fluids.

Introduction
The volume of butane extracted from natural gas in northwestern Peru has exceeded the market demand for many years. From 1941 until 1951, this excess butane was stored in a depleted reservoir. Although some additional oil was obtained as a result or butane storage, optimum recoveries from the butane injection process could not be expected in this reservoir because or unfavorable reservoir conditions. Therefore, San Pedro Block D was selected as a prospect for observing the operation or the solvent extraction process under controlled field conditions. The procedure used during the field test involved the injection or butane to form a flood bank followed by gas injection to drive the bank toward the producing well. Because the Block D reservoir was small and isolated from adjacent productive areas, the results or butane injection could be obtained in a very short time.
The San Pedro pool was discovered in May, 1946, with the completion or Well 3637 in the Parias sand. The results or subsequent development drilling indicated that the pool was divided into four small fault blocks. These blocks are labeled A, B, C, and D on the structure map in Fig. 1. Because this structure map differs somewhat from those normally used, it will be discussed in detail in the geological section.
Following the discovery well, three producers were completed in Block D by June, 1948. However, one or these was abandoned after producing only a small amount or oil. Subsequent pressure production behavior proved that the 20-acre Block D reservoir was isolated from the rest of the pool and that dissolved-gas drive provided the predominant source of reservoir energy. Therefore, secondary recovery operations were undertaken to increase the ultimate oil recovery from this block and, at the same time, to provide a controlled field test or the solvent extraction process.
The project was initiated in the Block D reservoir during Oct., 1951 by injecting butane into crestal Well 3794. During the 2.8-year period or butane injection, the rate or oil production from Well 3807, the well nearest to the point of injection.
A New Integrated Material Balance Equation for Reservoirs Containing Only Oil and Water: Line Drive
Authors: Lesem Louis B. , Guy W.T. , Crawford George W. 
Published: December 2007

Abstract
Some or the equations used by petroleum engineers in analyzing and forecasting the performance of oil fields depend only on the specification of the flux or pressure at a fixed boundary which is determined by the oil-water contact at the time of discovery. This method deals rigorously with the two-regional series-flow-problem actually involved in reservoir performance; namely, flow throughout the aquifer and within the reservoir proper. In the reservoir proper the two-phase liquid system [oil and water] and the pertinent physical properties of each at any time have considerable effect upon the behavior of the entire fluid flow system [aquifer-reservoir]. Consequently the equations developed by this analysis make possible the more accurate evaluation of reservoir performance and of oil-in-place from conventional pressure and production data and the more accurate forecasting of the future performance of a reservoir containing only oil and water subject to a linear drive.

Introduction
Several methods for the calculation of water influx into an oil reservoir have been published in which the mathematical treatment has been concerned only with flux in the communicating aquifer. For this reason the results obtained using these methods cannot be applied rigorously to predict the behavior of an oil reservoir subject to encroachment of water. A mathematical model which more nearly fits the existing physic situation in petroleum reservoirs is one that considers flow in both the oil and water bearing regions.
Although the oil-water boundary in a petroleum reservoir moves as oil is produced, the solution to the problem of flow in two regions having an immobile boundary should be a close approximation for short periods of time. If at the original oil-water boundary resistance to flow is high the relations developed are valid for longer periods of time.
The unsteady state flow of fluids in a homogeneous porous medium is assumed to obey the general heat flow equation. The fluid diffusivity in the outer regions differs from that in the inner region, and the inner region may be treated as a uniform fluid sink. The problem is solved in one-dimensional linear geometry.
Political Risk Insurance and Project Financing of Petroleum Projects BT the Overseas Investment Corporation
Authors: Mansbach B. Thomas 
Published: December 2007

Abstract
What is OPIC? U.S. Government Agency Designed to promote development through U.S. investment in LDC’sObligations are supported by the full faith and credit of the U.S. GovernmentOperate at a Profit - $58 million in 1979 Self-sustaingDue regard for risk managementNot in competition with commercial banks Operates either alone or in concert with: Commercial banksInternational financial institutions and regional development banksEximbank and other suppliers’ credit organizationsCurrent Status Five projects - Jordan, Ghana, Egypt, Greece and PakistanOver 75 registrations by more than 30 companies in 30 countriesOrganic program designed to meet industry needsAll information provided to OPIC is accepted on a privileged information basis Insurance Coverages Availability--Exploration and development/production stages Investor can take one or more of the coveragesInconvertibility - Coverage A Changes in currency transfer laws, regulations and procedures Active blockage -- 30 daysPassive blockage -- 60 daysDoes not cover devaluationMeasure of recovery -- transfer function: Local currency delivered in host country for dollars delivered in the U.S.Expropriation - Coverage B NationalizationCreeping ExpropriationMust last for six monthsExceptions: For example BankruptcyProvocationVoluntary agreementsNational government activity that does not violate international law standardsMeasure of recovery -- Net unrecovered costs (investment less cost recovery) in return for assignment of insured interest in project agreements In convession agreements, where there is no cost oil/profit oil formula, such a formula would be imputedWar/Revolution/Insurrection - Coverage C Damage to physical propertySpecial coverage for financial institutionsMeasure of recovery -- the lesser of original installed cost or cost of repair or replacementInterference with operations - Coverage D Closure of project due to personal physical hazard of project employees for six months due to war/revolution/insurrectionMeasure of recovery -- net unrecovered costs in return for assignment of insured interest in project agreementsDuring the first five years, either investor or OPIC may require a reassignment of interest in agreements to investor in exchange for return of compensation, without interest
SPE 921(A) Current Perspective On Gas Well Testing Objectives, Methods, Procedures, Analysis And Requirements Of Producers, Purchasers, Storers And Regulators - Producers
Authors: Schrenkel Jack 
Published: December 2007

Abstract
A brief review of the various methods of testing gas wells and examples of their interpretation is presented.
OBJECTIVES OF WELL TESTING - PRODUCERS
Gas wells are tested for several different reasons. Among these are tests to satisfy the requirements of State Regulatory Agencies, both for the initial test period and periodic testing for use in gas allocation formulas. Tests are made to determine present and future deliverability. Wells are tested to meet the requirements of pipe line companies as to contract specifications of deliverability, line pressure, volume, and quality of gas. Tests are also run to evaluate the efficiency of completion and to determine if the deliverability of the well can be permanently improved by various stimulation procedures.
One important objective is obtaining adequate physical tests to correctly select the production equipment in order that the maximum profit may be obtained from the gas supply and that delivery of gas can be maintained during severe weather conditions.
Well tests are used for the very important purpose of determining gas reserves. The two testing procedures which can be used to determine reserves are the "Reservoir Limit Test", which is a determination of the minimum amount of gas connected to the well from its drawdown characteristics, and the periodic measurements of bottom hole pressure plotted against the corresponding cumulative gas production. This data is used to supplement the reserve estimates made by the pore volume or volumetric method.
"Canadian Natural Gas Supply in the Context of North American Energy Requirements"
Authors: McNicholas John 
Published: December 2007

Abstract
I would like to begin my address by thanking the Society of Petroleum Engineers for the opportunity to speak to your Annual Conference about Canadian Natural Gas prospects and how they fit into the energy requirements of the North American continent over the next 20 years. It seems somehow an appropriate topic since the theme of this conference is "Energy Frontiers".
We in Canada are very optimistic about our future energy potential. We are one of the few industrialized countries which has benefited materially from the increase in real energy prices over the past 10 years. There is some truth in the comment that if OPEC had not existed Canada would have had to invent it. The fact of the matter is that Canada is a country which has a very large resource base and has a very exiciting energy future if energy prices are high but we are energy paupers if energy is cheap and abundant.
Our energy supplies are high cost compared to the costs of producing oil in the Middle East and if cheap energy prices, such as prevailed over the 1950's and 1960's, continued through the 1970's or 1980's much of our energy resource base would not be economic: this is true with a vengeance in terms of our future energy supplies which are typically at either a geographic or a cost or a technical frontier. So why are we optimistic? Why do we consider that we have an important role to play in the energy future of our continent? The answer, in large measure, lies in the fact that, as a country, we have barely begun to tap our frontier resource base; because recent trends in exploration in our conventional areas of exploration and production in Western Canada suggest a much larger potential than even the optimists would have suggested 3–5 years ago and because we know that the era of cheap energy is over.
An Alternate Approach to High Volume, A Long Stroke Pumper
Authors: Hollenbeck Alfred L. 
Published: December 2007

ABSTRACT
In September, 1978, a long stroke pumping unit capable of operating with an eighty (80) foot stroke at three (3) strokes per minute was placed in operation at a site in Ventura, California. The unit has provided a measured production rate of 850 BFPD from a pump depth of 10,000 feet with standard API rod pump parts making up the down hole pump. The testing program of one million cycles has proved that the major elements of this pumper are practical and reliable for oil field service.
Thermal History Reconstruction and Estimation of Formation Temperature Using Wireline Formation Tester Measurements
Authors: Zazovsky A. , Haddad S. , Tertychnyi V. 
Published: December 2007

Abstract
A new method for estimating formation temperature from wireline formation tester temperature measurements has been developed1. This method is based on the reconstruction of thermal history, which involves drilling, no-mud-circulation and pumping-out phases, using the model of heat transport in the formation. The model calibration is achieved by fitting the predicted temperature at some intermediate distance from the borehole for the temperature data measured in flowline during pumping-out. The temperature found in intermediate zone is then extrapolated to the boundary of cooled zone surrounding borehole for estimating initial formation temperature.
The forward model used for thermal history simulation is simple and robust. It does not involve the borehole temperature modeling during drilling and can be calibrated with a single parameter - either the average mud temperature opposite the tested interval or the average heat flux from the formation during drilling. Although this model cannot predict accurately the initial phase of thermal history (drilling and no- mud-circulation), it becomes adequate for the pumping-out phase when the details of borehole temperature variation with time during drilling become insignificant. The only parameter that affects solution during this phase is the total amount of heat extracted from the formation during drilling.
This approach in order to be successful imposes some constraints on the timing of thermal history phases. In particular, the no-mud-circulation phase should not be too long and the pumping-out phase should not be too short, otherwise the deterioration of resolution may occur. The examples are given that illustrate the capabilities of new technique.
Preventing Differential Sticking and Mud Losses Drilling through Highly Depleted Sands – Fluids and Geomechanics Approach
Authors: Benaissa Saddok , Bachelot Alain , Ricaud Jean , Arquey Gerard , Yi Xianjie , Ong Seehong 
Published: December 2007

AbstractDrilling through depleted sands can result in a multitude of problems such as lost returns, differential sticking, difficult logging and/or not being able to reach the target depth. Often curing lost circulation can be difficult and costly as a result of associated nonproductive time and escalating mud costs. Remedies such as cement plugs, squeezes, expandable liner and casing while drilling can be costly solutions.The use of fluid management techniques, team efforts and proper engineering have lead to the development of an innovative approach to prevent problems and avoid the complex processes of curing mud losses and freeing stuck pipe. This new preventative approach with water-based mud has been applied in several fields, while drilling through a series of highly depleted sands and has proven to be very effective in preventing differential sticking and mud losses.Although operationally successful, the geomechanics and the fluid design resulting in these successes are not well understood. A geomechanical analysis indicates that two mechanisms might contribute to the success: (1) The near wellbore region is turned into a non-porous rock because the particles in the new mud tend to block the pore spaces. The theory of poroelasticity indicates that fracturing pressure is increased by reducing the difference between mud pressure and the pore pressure immediately behind the borehole, which for non-porous rock is zero. (2) Because of this blockage, it is possible that the near wellbore rock strength is increased. This strengthening effect decreases tangential stress and increases fracturing pressure.The geomechanics model can be used to define the operational limits of various mud weights with proper drilling fluids design. This model would enable a consistent and focused approach on drilling fluid design to effectively mitigate massive fluid losses associated with drilling through severely depleted sands or in narrow pore pressure/fracture gradient environments.
Reservoir Discription from Production Data
Authors: Callard Jeffrey G. 
Published: December 2007

ABSTRACT
Reservoir limit test analysis for wells producing at constant pressure can be made from readily available production data or production decline curve plots. Constant pressure production is not uncommon for oil and gas wells flowing into separators, pipelines, or artificial lift wells produced at capacity.
Determination of reservoir pore volume contacted by a wellbore within either natural or no flow boundaries is the main objective of the reservoir limit test. When combined with infinite acting analysis for permeability, effective wellbore radius or fracture length can be determined.
A case history of a low permeability gas reservoir previously published1 is used to apply the techniques of transient rate analysis for a bounded reservoir in combination with pressure transient analysis for an infinite acting system to provide evaluation of sand frac stimulation treatments.
Reservoir Potential as a Function of the Geological Setting of Carbonate Rocks
Authors: Lapre J. F. 
Published: December 2007

ABSTRACT
The geometry and reservoir properties of carbonate rocks often show a relationship with the original depositional conditions. The critical depositional parameters, with regard to the development of reservoir properties, are the sedimentary fabric and the genetic external geometry. The fabric can be defined as determining the ‘reservoir potential’.
Accordingly, it is of importance to know the reservoir potential of the various carbonate deposits, e.g. build-ups, shoals/banks, and carbonates of lagoonal to tidal nature. Their sedimentary-framework can comprise one, or both, of two basic types of reservoir potential – GRAIN-SUPPORTED, MUD-SUPPORTED ROCK.
Depending on burial compaction, shallow and deep-burial diagenesis, the reservoir potential can be – preserved – enhanced – destroyed. Also, either grain or mud support can be selectively enhanced or destroyed. Although often a grain-supported reservoir rock will have better reservoir potential than mud-supported rock, which it may retain, occasionally this relationship will be reversed by certain types of diagenesis.
The control of the distribution of the reservoir potential within the various carbonate deposits depends on the relationship in time between rate of carbonate growth and the evolution of the topographical relief of the marine shelfs. Examples of the control are shown.
In addition to the variation in the distribution of reservoir potential, the distribution of bed-parallel barriers to vertical cross-flow can be predicted on the basis of the overall characteristics of the sedimentary process. The rocks which most likely contain barriers to vertical cross-flow are the sediments which occur at the interface of cycles of deposition.
Schematic drawings and summary-diagrams of field studies demonstrate the above relationships, which can also be used for the design of sections for reservoir engineering simulation.
The use of Bottom Hole Pressure Analysis in Optimizing Frac Design-Anadarko Basin of Western Oklahoma
Authors: Lent J. T. , Nickell R. L. , Davis W. E. , Allam A. M. 
Published: December 2007

ABSTRACT
For several years, fracture designs for the deep Morrow in the Anadarko Basin were made using assumptions of the formation parameters: Permeability, bottom hole pressure, and fracture conductivity. Recent pressure transient analyses have shown that these assumptions in some cases were incorrect for permeability and bottom hole pressure. In addition, laboratory testing with sintered bauxite proppants has produced a means of achieving sufficient fracture conductivity to sustain production increases obtained with successful fracture stimulation.
A New Method to Account for Producing Time Effects when Drawdown Type Curves are Used to Analyze Pressure Buildup and Other Test Data
Authors: Agarwal Ram G. 
Published: December 2007

ABSTRACT
Currently, type curve analysis methods are being commonly used in conjunction with the conventional methods to obtain better interpretation of well test data. Although the majority of published type curves are based on pressure drawdown solutions, they are often applied indiscriminately to analyze both pressure drawdown and buildup data. Moreover, the limitations of drawdown type curves, to analyze pressure buildup data collected after short producing times, are not well understood by the practicing engineers. This may often result in an erroneous interpretation of such buildup tests. While analyzing buildup data by the conventional semi-log method, the Horner method takes into account the effect of producing time. On the other hand, for type curve analysis of the same set of buildup data, it is customary to ignore producing time effects and utilize the existing drawdown type curves. This causes discrepancies in results obtained by the Horner method and type curve methods. Although a few buildup type curves which account for the effect of producing times have appeared in the petroleum literature, they are either limited in scope or somewhat difficult to use.
In view of the preceding, a novel but simple method has been developed which eliminates the dependence on producing time effects and allows the user to utilize the existing drawdown type curves for analyzing pressure buildup data. This method may also be used to analyze two-rate, multiple-rate and other kinds of tests by type curve methods as well as the conventional methods. The method appears to work for both unfractured and fractured wells. Wellbore effects such as storage and/or damage may be taken into account except in certain cases.
The purpose of this paper is to present the new method and demonstrate its utility and application by means of example problems.