bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recovery Optimization Through Infill Drilling Concepts, Analysis, and Field Results
Authors: Driscoll Vance J. 
Published: December 2007

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

Abstract
This paper gives theoretical concepts and some supporting mathematical model and field performance data which demonstrate factors t at performance data which demonstrate factors t at can be involved in recovery increases by drilling. Many of these factors relate to various reservoir heterogeneities and are quantitatively more important in fluid injection projects. Recovery increase by infill drilling projects. Recovery increase by infill drilling of low-permeability waterflood projects can be due to as many as nine different factors with varying degrees of technical difficulty to specifically quantitize. However, based on performance and certain theoretical knowledge performance and certain theoretical knowledge and concepts, reasonable factors involving judgment can be developed as to percent of original oil-in-place recovery increase.
Attractive conventional growth economics based on increased ultimate waterflood recovery are indicated for areas of low-permeability, slowly depleting reservoirs with relatively large amounts of oil in place. This is in addition to substantial increases in current rates of production and present worth. Typically, an increase on the order of 4 percent of the original oil in place will be percent of the original oil in place will be gained by infill drilling from 40- to 20-acre spacing. However, this can vary by a factor of two or more depending upon the specific situation.

Introduction
There is probably no place more than reservoir engineering where a spirit of Hegelian dialecticism applies. That is, there is "truth" and "error." However, in the truth there still exists some error. Consequently, with time a new truth evolves that is purged of some previous imperfections. In the 1940's, Uren, previous imperfections. In the 1940's, Uren, Muskat, and predecessor companies of Exxon, among others, published thinking and results properly decrying misapplications of Cutler's properly decrying misapplications of Cutler's rule. This had been a previous empirical observation which indicated that primary recovery in densely drilled portions of fields was greater and proportional to the square root of well density. It was generally shown that this was due to migration from less densely drilled areas of the same fields rather than an increase in over-all recovery.
The tendency since about the 1950's has been to consider increased recovery by infill drilling as negligible or only to consider it where some one factor in a particular reservoir had a dramatic effect upon recovery. This has been partly due to past limitations on ability to realistically describe and simulate actual reservoir heterogeneity and displacement.
A Comparison of Actual vs Calculated Ground Level SO2 Concentrations During Field Flaring of Sour Gas
Authors: Stan P.W. , Bossert D.W. 
Published: December 2007

Abstract
Due to the tightening of air pollution control regulations, all sour gas flaring operations, such as used on well cleanups after performing workovers, have to be performed in a manner which will not yield performed in a manner which will not yield SO2 ground level concentrations in excess of the regulations, as calculated by the Pasquill equation. Amoco personnel using meteorological data, land terrain, and the Pasquill method of calculation, set up mobile monitoring equipment to measure and, therefore, control flaring operations to ambient air standards. This provided the opportunity to obtain a comparison of actual ground level concentrations to Pasquill calculated concentrations. The data indicates that downwind ground level concentrations can better be determined by measurement with mobile monitoring units than by theoretical predictions.

Introduction
Flaring of sour gas wells in the Crossfield D-1 Unit located 30 miles north of Calgary is required to recover workover fluids and enable the wells to produce against the gathering system back pressure. Government regulations require that the flaring of sour gas shall not result in exceeding the maximum half-hour ground level SO2 concentration of 0.20 ppm for populated areas. Five large volume acid frac workovers were performed during 1973–1974 and these wells had to be flared within ambient air standards set by the government at levels calculated by the Pasquill equation.
A computer program utilizing the Pasquill method of calculation was used to determine a wind restriction above which flaring operations would be discontinued or new stack dimensions proposed so that the maximum allowable SO2 concentration is not exceeded for the most disadvantageous weather conditions and maximum flaring rate expected. The maximum wind speed allowed by the Pasquill calculation for the existing stack (75 ft. × 6 inches) was calculated to be 10 mph. The highest commercially available portable flare stack is 160 ft. × 8 inches which would impose a 15–20 mph wind speed limitation by calculation. Both these alternatives were impractical for the Crossfield Area where wind speeds may average 20–25 mph. Discontinuing of flaring operations due to a wind speed limitation during the initial flaring operations may result in the wellbore loading up with fluid.
Blackback Field Development - An Example of Technical and Commercial Risk Mitigation in a Deepwater Marginal Field
Authors: Perrett T.L. , Garven I.M. 
Published: December 2007

Abstract
The Blackback structure is a large, top-Latrobe, eroded and faulted anticline within the Gippsland Basin of south east Australia. Despite its large areal extent, it is a commercially marginal field due to reserves uncertainty, deep water and the practical difficulties of development. Proximity to existing infrastructure helps to make this marginal field commercial.
Five wells have been drilled on the Blackback feature, and have intersected reservoirs with greatly varied geological and geophysical properties. The resulting uncertainty over the ultimate recovery remains, despite the five wells drilled to date. This paper describes the geological and development risk mitigation undertaken by a non-operating Joint Venturer to reduce the technical and commercial uncertainty pertaining to a second phase of development. This includes the development of a predictive depositional model targeted at the upside potential and maximum use of existing infrastructure.
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Money for Energy: The Role of International Banks
Authors: Yurchyshyn George B. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
The financing of large energy projects is a well developed area of lending in the United States. Over the past thirty or forty years billions of dollars have been lent by the public market, by insurance companies, and public market, by insurance companies, and by banks to finance the impressive grid of pipeline that overlays the U.S. New pipeline that overlays the U.S. New petrochemical plants, refineries, and nuclear petrochemical plants, refineries, and nuclear power plants have had few financing problems, power plants have had few financing problems, at least until environmental concerns and governmental economic restraints made further investment in these areas more risky.
Most bankers are confident about the availability of sufficient money to finance the large energy projects proposed for various sections of the U.S. and for adjacent coastal waters. The U.S. possesses the world's largest capital market whose main strengths lie not only in the dollar amounts that may be raised but also in the different kinds of lenders who are able to offer funds on different terms, giving projects a certain flexibility in matching their particular borrowing needs with an appropriate lender. Periods of economic uncertainty such as we Periods of economic uncertainty such as we are seeing in 1974 may make some types of financing unattractive, but financing is generally available. On the international side the picture is not as bright and significant problems can be anticipated. outside the U.S. we presently see three broad funding sources:Domestic capital markets in foreigncountries.Export financing schemes of individualcapital equipment producing countries.International capital market.(A) Eurocurrency loans(B) Eurobonds
Let us briefly look at each of these potential funding sources. potential funding sources.(1) Domestic Capital Markets:No foreign capital market approaches the size of the U.S. market. Even collectively, the capital markets of all the West European countries equal only a fraction of the U.S. capital market. It is rare in West European markets to see stock or bond issues in excess of $100 million. Foreigners borrowing in European money markets are even more restricted. Switzerland, the fabled land of untold wealth, rations access to its capital market very carefully, and few foreign borrowers have ever floated a bond issue in excess of the S.Fr. equivalent of U.S. $30million. Although steps are being taken in individual countries to make their capital markets more attractive to investors, these are long-term plans and goals from which today's projects will not benefit.
Long-Term Effects Of High Temperature On Strength Retrogression Of Cements
Authors: Eilers L.H. , Root R.L. 
Published: December 2007

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

Abstract
Neat Portland cement systems lose strength and become permeable at temperatures above 250 degrees F. This deterioration usually is more extreme over the first few days or month of heating but is usually not severe enough to cause disintegration of the neat cement. After this initial regression many neat Portland systems will regain a portion of Portland systems will regain a portion of their strength and reduce in permeability. This temperature regression of cement can largely be prevented by using about 35 per cent very fine silica sand. The strength can be maintained or increased but permeability will increase. Most additives for oil well cements can be included in such a silica stabilized system without extensive effect due to temperatures up to 600 degrees F. An exception to this is fly ashes and, to some degree, natural pozzolans. These are stable at 450 degrees but are losing strength and recrystalizing 600 degrees F.

Introduction
The deterioration of Neat Portland cement at temperatures above 250 degrees F (120 degrees C) has been known for many years. Menzel proved that fine silica added to a Portland cement paste would improve the strength of cements cured at elevated temperatures.
An increasing number of wells are being subjected to these elevated temperatures each year. Deeper and hotter oil and gas wells are being drilled and other wells are being subjected to hot water, steam, or fire flood methods. High temperature geothermal wells are also increasing in number each year. The cement in these wells will be subjected to elevated temperatures from bottom to top. It is probable, therefore, that the surface and intermediate strings on many of these wells are not adequately protected from deterioration.
Sand Consolidation Systems Placed with Water
Authors: Murphey J.R. , Bila V.J. , Totty K. 
Published: December 2007

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

Abstract
Sand consolidation systems using resinous materials have been developed which require only water (brines) in the placement procedures The use of water treating fluids is solving several important problems in the field associated with current consolidation methods which use oil placement fluids.
The brine treating fluids are easily handled and have presented no disposal problems, particularly on offshore locations. The desirable particularly on offshore locations. The desirable weighting and no fire hazard characteristics of brines have improved safety. These aqueous fluids can be used in gas and non-potable water (source or injection) wells where it is undesirable to use oils. Waters to prepare the brine treating solutions are readily available. Formation brine, fresh water, bay and sea waters have all been used. The ready availability of these fluids has resulted in reduced "storage tank" requirements on water job sites and have eliminated transport needs required in getting treating oils to offshore facilities. Considerable volume of oil is being saved on each application by using brines.
The paper describes two separate consolidation procedures. One involves the consolidation procedures. One involves the consolidation of formation sands with neat resins using brine placement fluids and the second describes the placement fluids and the second describes the packing of formations with resin-coated sand packing of formations with resin-coated sand placed in a water carrier. With both systems placed in a water carrier. With both systems an aqueous hydrochloric acid solution is used to overflush catalyze the placed resin resulting in consolidation of the sands. Deemulsifier surfactants may be used in all treating solutions including the organic resin.
The first technique, involving the placing of neat resin, has been successfully applied in a bull-head squeeze procedure requiring no or minimal rig facilities on location.
Laboratory results and field development data on fourteen initial applications are presented. presented

Introduction
The petroleum industry's sand problems are both widespread geographically and persistent historically. Sand control has persistent historically. Sand control has consequently meant a succession of solutions.
Evaluation Of The Alberta Tar Sands
Authors: Sah R.C. , Chase A.E. , Wells L.E. 
Published: December 2007

Introduction
There are three major tar-sand areas in Alberta: the Alberta Tar Sands, the Cold Lake Tar Sands, and the Peace River Tar Sands. The total reserves in place are estimated at 1,000 billion barrels, and recoverable reserves are estimated at 400 billion barrels.
The Alberta Tar Sand area is the largest of the three. It covers 5.75 million acres. As shown in Fig. 1, it is located in the northeast part of Alberta, between Township lines 77 and 103 and between Range lines 6 and 20, west of the Fourth Meridian. The estimated reserves in place, in terms of the depths from which they have to be recovered, are tabulated below: Reserves Depth (billions of barrels) 0 to 100 ft 45.1100 to 1,000 ft 373.9Deeper than 1,000 ft 207.0 Total Resreves in Place 626.0
The Tar Sands belong to the early Cretaceous. Fig. 2 shows the simplified geological cross section' along the dashed line in Fig. 1 from A to B. As the Elk Point salt (fine cross-hatch on Fig. 2) collapsed, the overlying Beaverhill Lake limestone formed a basin for Cretaceous sediments. The overlying tar sands (in black) are unconformable to the limestone. The tar-sand sediments are deposited in predeltaic, deltaic, and post-deltaic environments, Pre-deltaic and deltaic sediments are rich in tar, and their matrix materials contain 90 to 95 percent by weight of quartz.
The post-deltaic deposits are poor in tar and their matrix materials contain only 50-percent quartz by weight.
The tar differs from conventional oils. It has low gravity (6 degrees API at 60 degrees F), high viscosity (3,000 to 300,000 poise at 60 degrees F), and is undersaturated in hydrogen.
The bituminous tar sand will be mined and physically removed to an extraction plant. There, it will be processed and upgraded to produce "synthetic" crude. This mining and processing operation involves a large capital investment in the plant and equipment. Also considerable are the daily costs of mining and transporting large quantities of tar-sand ore. It is important, therefore, to have an accurate evaluation of the tar-sand deposit before so great an investment is committed. This requires a large number of test holes from which the needed information can be derived.
An evaluation system involving the analysis of a suite of well logs from each test hole can be used to appraise these ore bodies. Such analyses of the large volumes of data available from logging programs in many test holes are best handled by computer. Also, use of the computer makes possible an evaluation system which has a high capability possible an evaluation system which has a high capability for producing all of the desired answers. Furthermore, machine computation of well logs is fast and minimizes the problems associated with laborious intensive-evaluation problems associated with laborious intensive-evaluation systems done manually.
The Use of Centrifugal Separators for Offshore Gas Production
Authors: Lobdell W.R. , Ayers L.M. 
Published: December 2007

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

Introduction
The use of centrifugal force to separate fluids is a proved process that has been applied by many industries. The force is explained in college physics textbooks under uniform circular motion where Newton's laws of motion are discussed. A classic textbook example describes an object of known weight that is held in a circular path by a string of known length, and the weight is moving at a constant speed. The inward force that is developed is known as the centripetal force. The equal and opposite reaction that is in the outward direction is known as the centrifugal force. This is the force that we use to separate gas well fluids in a centrifugal-type separator.
The flowing pressure at the wellhead furnishes the energy for the process. Upon expansion to a lower pressure at the wellhead choke, the natural gas, condensate, and water flow to the centrifugal separator for rotation and subsequent separation. The fluids tend to separate in layers of uniform density. Water collects on the internal surface of the separator, condensate flows on the water, and the gas flows in a circular pattern in the center of the vessel.

FUNDAMENTALS
The following formula for centripetal - force summarizes the process.
2WVFc = ———,gR
where Fc = centripetal force, lbW = weight of the fluids, lbV = velocity, ft/secg = gravity constant, 32 ft/sec/secR = radius of the circle, ft
The centripetal force, Fc, is that force in the inward direction, expressed in pounds, that is developed when the fluids are directed in a circular path in the separator. The centrifugal force is an equal and opposite reaction to the centripetal force; therefore, calculated values for Fc are vend for the centrifugal forces in the outward direction.
The weight of the fluids can be calculated from the fixed dimensions of the internals of the vessel, the operating pressure, and temperature in the separator, and the gas-condensate ratio and gas-water ratio of the flowing stream.
Rock Structure Characterisation Through Imaging Techniques Integration
Authors: Radaelli F. , Balzarini M. , Nicula S. , Ortenzi A. 
Published: December 2007

Abstract
Imaging techniques are widely used in the oil industry, but their integration is much less common.
Here we present the relevance, in rock structure characterisation, of the integration of Magnetic Resonance Imaging (MRI), X-ray Computed Tomography (X-ray CT) and Scanning Electron Microscopy (SEM), based on different physical principles and investigating different rock volumes.
A set of experimental studies on various fields with different lithologies (chalk, brecciated dolostone, limestone, calcarenite and conglomerate) is presented.
The results of these applications demonstrate that the integration of different approaches greatly improves the characterisation of internal rock structure.
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Realistic Fault Modelling of Stacked Reservoir Sands in the Niger Delta
Authors: Onyeagoro U.O. 
Published: December 2007

Abstract
Hydrocarbon bearing fields in the Niger Delta typically comprise multiple reservoirs stacked over intervals of 10,000ft thickness. Listric faulting is prevalent in these fields causing problems in generating accurate representation of structural geometries. In SPDC Nigeria a study was initiated to develop a route to incorporate realistic structural geometries in static and dynamic reservoir modelling. This was applied to the Soku field using the 3D structural modelling program Earth Vision and Shell's proprietary 3D reservoir modelling package GEOCAP. The field, covering an area of approximately 112km2, was discovered in 1957. In-place volumes are estimated at 900 MMstb of oil and 5000 MMMscf of gas. The results of this study are used mainly in the current infill drilling campaign and will in future be used to support dynamic reservoir simulation studies. In Earth Vision, a complex fault tree diagram was used to describe the arrangement of the faults in an hierarchical order. A structural model with a thickness of 4000ft was constructed consisting of 20 realistic faults and 25 fault- blocks. This initial fault framework was then exported to the GEOCAP reservoir modelling system for integration with well planning and reservoir engineering software. Subsequently, the internal reservoir architecture was modelled integrating 3D seismic, sedimentological, petrophysical and reservoir engineering information, honouring all available well data. The GEOCAP well planner was used within this realistic fault model to plan for infill drilling locations. The first of these wells was recently completed and successfully tested to 100 MMscf/d gas and some 7,000 b/d condensate. The procedure for representing realistic faults was instrumental to the success of the well and is recommended as a routine for future well planning and reservoir studies in the Niger Delta.
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