bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Drainage Area and Producing Rate on Horizontal-Well Oil Recovery in Bottom
Authors: Permadi P. 
Published: December 2007

Abstract
Previous studies on horizontal well applications for bottom water drive reservoirs mostly assumed no pressure loss within the horizontal wellbore in predicting the performance. Except at low rate production, such an assumption could lead to over estimation of the oil production. The results are therefore not conclusive yet. Since it is a high cost technology, a plan of reservoir development with the use of horizontal well requires optimization of the acreage and production rate. The real challenge then and thus the main objective of the present study is to investigate the effect of drainage area and rate of production on the oil recovery. This work employs a semi-empirical method that has been successfully validated using field data. The method can also be used to evaluate the effect of wellbore length and its position and reservoir anisotropy on the production performance.
Results obtained show that, for the same well length and same withdrawal rate, the fractional oil recovery decreases with increasing well acreage. Also found here is that the rate of recovery can be enhanced by withdrawing a higher volume of produced fluids although breakthrough time for water is shortened. By taking this advantage, a larger spacing therefore can be overcome by increasing both production rate and the length of horizontal wellbore section proportionally to achieve a high oil recovery for a shorter production period. These findings have not been previously reported and are of importance in relation to the economic point of view of reservoir development. Results also demonstrate that a higher oil recovery may be obtained by use of a longer horizontal well section. The effect of wellbore placement on the recovery along with other results will be discussed in detail.
The ultimate goal of this paper is to provide engineers the strategy for Optimizing the development of bottom water drive reservoirs using horizontal wells. A simple procedure for forecasting the production performance is clearly presented.
P. 487
An Integrated Approach to Estimate Well Interactions
Authors: Panda M.N. , Chopra A.K. 
Published: December 2007

Abstract
Injector-producer interaction, that is, how well a producer is connected to each of its surrounding injectors, is used in designing efficient injection schemes and infill drilling programs. Determining well interaction in a field with multiple injectors and producers is a challenge because of the heterogeneity of the reservoir. In addition, the presence of subseismic faults, both conducting and nonconducting, further curtails our ability to estimate well interaction indices.
Currently, the injector-producer interaction is estimated by visually cross correlating injection and production rates of different well pairs in a pattern. Regional discontinuities in reservoir properties including faults and pinchouts are inferred from the cross correlation. Such statistics-driven methods are stable as shown previously in many such fields of applications. There are, however, two problems with this approach: firstly, the results obtained using the cross correlation are non-unique and secondly, the process is extremely time consuming.
This paper presents a new integrated approach to determine the injector-producer interaction. First, a multi-variate data set consisting of production, injection, petrophysical, sand/shale, and well location information is generated. An artificial neural network (NN) is then trained to estimate the well interaction between different well pairs. The estimated well interactions are used to determine the presence of heterogeneities, such as faults, pinchouts, regional permeability trends etc. Results show that the new integrated app roach can quantify injector-producer connectivity more accurately, consistently, and inexpensively than the conventional methods. The new method will, thus, facilitate better reservoir management of fields where the knowledge of injector- producer interaction can affect recovery efficiency, sweep, reservoir performance, and infill well placement.
P. 517
Experience of Side-Track in Bombay High Field
Authors: Raju A.V. , Ramanan S. , Chaurasia R.D. , Jha K.K. 
Published: December 2007

Abstract
The Bombay High field is a giant offshore oil field in India. The field which is on oil production from 1976, contains two major reservoirs and is divided into Bombay High North and Bombay High South. L-III limestone is the main reservoir and produces oil from the entire field and L-II limestone produces oil from Bombay High North.
The heterogeneous nature of the L-III reservoir complicates the recovery process. The current development has resulted in over injection in certain regions/zones and under injection in other areas. Non-uniform movement of water, with considerable amount of oil left undrained is observed throughout the field. Poor primary cementation in certain wells further aggravates the problems due to the pre-mature break-through of water and gas.
A large proportion of the work-over jobs are done to contain the cusping of gas, cycling of excessive water and to repair the channels behind the casing. Conventional cement squeeze jobs have yielded moderate results and few gel treatments in production wells have not been successful.
The most successful results in recent times, in increasing oil production from sub-optimal producers, have come from Long Drift Side Track (LDST). In this operation, the well is sidetracked to some distance away from the original wellbore, to a relatively undrained area and recompleted with special attention on cementing operation. The present success ratio is high. LDST amounts to a new well in a relatively undrained area by utilizing the existing slot. This has been found to be a viable option for well production optimization. However, in future, as in the past, the decision on side-track needs to be made on well by well basis only.
P. 531
Evaluation of Economic and Technical Uncertainties for Indentification of Economic
Authors: Jain Prabuddah , Raju A.V. 
Published: December 2007

Abstract
The Government of India has recently approved a new exploration licensing policy. The upstream public sector companies are to compete along with private sector companies but are to get the same fiscal and contract terms as are available to private companies. The public sector companies are also planning to acquire acreages and develop oil & gas fields within and outside India, in association with private and multinational oil companies. Therefore, the evaluation of technical and economic uncertainties in the field development and asset valuation in totality assume significance.
Investment decisions in oil field development are normally based on perceived ability to enhance asset economic value. Present evaluation practices are based on deterministic approach estimating most likely reserves and producing rates, development plans, capital investment needed and carrying out sensitivity analysis for important variables. This approach has short coming in that it does not consider the uncertainties in reserves, producing rate, capital investment, operating expenses and price realization.
This paper presents an integrated approach applied to reservoirs, at initial stage of development and at mature stage, using simulation modeling considering technical uncertainty about hydrocarbon volumes estimated and production profiles: and economic uncertainty about capital investment, operating expenses, prices, inflation and exchange rates, to determine the economic volatility and the option value.
P. 615
Influence of Pore Size Distribution on Damage Profile
Authors: Aminian K. , Bilgesu H.I. , Ameri S. 
Published: December 2007

lnfluence of Pore Size Distribution on Damage Profile

Abstract
This paper investigates the use of particle movement in porous media as a tool for evaluating pore size distribution. During their movement in porous media, the particles plug the pore connections that are smaller in diameter than the particles. The plugging of the pores result in permeability reduction (damage). If the particle size is varied within a certain range, the damage profile can reflect the pore size distribution.
A model for simulating porous media as a system of connected pores has been developed. Monte-Carlo simulation was used to assign pore size distribution to the porous system. The damage caused by uniform-sized particles is determined for a number of pore size distributions. The particle size is then varied to establish the damage profile.
The model studies indicate a close relationship between size distribution and damage profile. A database to assist with experimental data analysis has been developed.
P. 641
"Micro-Bubbles": New Aphron Drill-In Fluid Technique Reduces Formation Damage in Horizontal Wells
Authors: Brookey Tom 
Published: December 2007

Tom Brookey, SPE, Acti Systems, Inc.

Abstract
Horizontal drilling technology has enhanced production through increased ability to expose formation openings. In most cases, these openings are fractured, vugular, or otherwise highly permeable. Many are drilled through low-pressure reservoirs where drilling fluid losses occur and often cause severe formation damage. The use of conventional lost circulation control materials are restricted due to the downhole tools required, and borehole sealing techniques are mostly ineffective in this type of application.
A novel new drill-in fluid is being used to drill horizontal and high angle wells through these damage-prone reservoirs. This fluid combines certain surfactants and polymers to create a system of "micro-bubbles" known as aphrons encapsulated in a uniquely viscosified system. These aphrons are non- coalescing and recirculatable so that density reduction is accomplished without expensive air or gas injection.
A unique feature of the micro-bubble network, stopping or slowing the entry of fluids into the formation, creates downhole bridging. The unique viscosity builds to create a resistance to movement into and through the zone so that a true noninvasive, at-balance fluid is achieved. Test data shows the enhanced hole cleaning and suspension properties.
Case histories show that drilling problems are reduced, mud losses are prevented, and completions are simplified. Natural production was achieved in many cases. No problems with formation damage or inhibited production were seen.
P. 645
A Study of CO2 Effects on Reservoir Fluid Sensitivites in Preparation to a CO2 Flood
Authors: Freeman Randall , Lopez Henry , Metcalf Steven 
Published: December 2007

A Study of CO2 Effects on Reservoir Fluid Sensitivities in Preparation to a CO2

Abstract
Asphaltic sludge is believed to be the result of destabilization of the colloidal asphaltenic materials present in reservoir crude oil. One destabilization mechanism involves lowering the pH, thus neutralizing base materials in the crude which act as stabilizers. This can be enhanced by the presence of some metallic ions (Fe3+). Permian Basin reservoirs are known to have sludging problems associated with acid simulation for these very reasons. However, introduction of CO2 as an injection fluid for flooding has the potential for having the same effect and enhancing the effect during acid stimulation.
This study examines the compatibility of reservoir oil and water from San Andres wells in and around a CO2 injection pilot project in the Permian Basin. Samples were collected in 1996 prior to commencement of the pilot project and again in 1997 after 10 months of CO2 injection. Evaluation was made in the presence of CO2. Several examples are provided of asphaltic sludge being generated from reservoir crudes when mixed 50:50 with produced water and in the presence of CO2 at 900 psi and 90 F. A comparison of sludge formation as a function of the resin to asphaltene ratio is presented, In addition evaluation of floe acid stimulation package to avoid sludge in the presence of CO2 has been included. The feasibility of CO2 flooding, as it relates to asphaltic sludge formation, should be addressed prior to commencement of CO2 injection through the use of complete oil and water analyses. Fluid compatibility studies are indicated to be an ongoing operation to protect against sludging during acid stimulations.
P. 657
A New Material and Novel Technique for Matrix Stimulation in High-Water-Cut Oil Wells
Authors: Chang F.F. , Thomas R.L. , Fu D.K. 
Published: December 2007

Abstract
A new process has been developed that effectively diverts acid away from zones with high water saturation into hydrocarbon zones. This process is designed to increase the success in matrix acidizing treatments. Because of the relative permeability effect, aqueous acid predominantly enters the zone with highest water saturation, resulting in stimulation of the water zones and an increase of water cut. Although foam can be used to divert acid from the "aquifer" to the damaged oil zones, nitrogen is not readily available in some areas and additional handling equipment is required. A new non- particulate, non-gaseous material has been developed to effectively divert acid away from highly water saturated zones. The material forms a highly viscous plug when it contacts water in the matrix yet degrades when mixed with oil in the matrix of the formation.
This paper discusses in detail the diversion technique and laboratory results. Laboratory tests conducted in a dual-core flow apparatus showed excellent diversion from a water-rich zone to an oil-rich zone, as well as from a high-permeability formation to a low-permeability formation.
P. 675
Investigation of Completion-Quality Measures Used for Incentive Criteria in Operations on High-Permeability Sandstone Formations
Authors: Chapman B. J. , Howard W. J. , Gardiner N. H. 
Published: December 2007

Abstract
Some measure of completion quality is often used to determine the success of the completion operations performed on petroleum wells. Some of the parameters used to determine the quality of the completion are productivity index (J), skin factor (S), productivity ratio (Jactual/Jideal), pressure because of skin (ΔPskin), and production rate (Q). These parameters often determine the bonus or malice compensation for the service company that has entered into this type of agreement with the well operator. It is in both parties' interest to fully understand and document the ways these parameters will be measured. All these parameters can be dependent on the rate the well is produced.
Knowing or correctly assuming reservoir characteristics such as permeability, net height, and fluid characteristics is very important. Productivity ratio is the single most direct measure of how well the completion was performed. It is often difficult, however, to reach consensus on the exact value of the productivity ratio given that a knowledge of how the well would have performed under ideal conditions is required. Pressure drop because of skin can reflect pressure losses because of completion techniques; however, the value of the pressure drop depends on the rate at which the well is produced. Skin factor is dependent on the permeability of the unaltered reservoir. Consequently, the use of skin factor should be limited to cases where there is knowledge of the permeability and net producing-formation height.
Productivity index (J) is a commonly measured parameter that is dependent on only rate and total drawdown. Relating productivity index to the quality of a completion does not account for normal formation drawdown, which can be affected if permeability and net formation height are different than expected. Basing completion-quality incentives on production rate is the least desirable option because of the many variables that affect rate. Some of these variables, such as wellhead flowing pressure and the time during the well's life when the rates are measured are controllable. Others, such as permeability, net formation height, and reservoir pressure, must be assumed.
The three basic types of incentives used with completion-efficiency measures are reviewed in this paper. These three types of incentives are the tools most commonly used for aligning interest in the business relationship between the operator and service provider. This enhanced business relationship and the incentives are based on a win-win strategy that is important for all parties.
Occurrence Of Overpressures And Its Implications For Hydrocarbon Exploration In
Authors: Bhagwan Sahay , Singh O.D. , Awadhesh Rai , Talukdar B.N. 
Published: December 2007

Abstract
Assam-Arakan basin having an area of approximately 100,000 sq km. is one of the main, proven and highly prospective petroleum province in the north eastern part of India. Upper Assam valley contains 7000 m of sediments under its alluvial cover. On the southern edge of platform, lies the mobile belt of Assam geosyncline with very thick sediments of the same age as in the shelf region.
Over pressure horizons in northeast India occur mostly in the geosynclinal region in the western Tripura, Cachar as well as in schuppen belt and adjoining Arunachal Pradesh areas, mostly in the younger Tertiaries of Miocene-Pliocene age. In the Tripura area, abnormal high pressures to super high pressure horizons occur in Middle to Lower Bhubans of Surma group in almost all the structurs so far drilled. Deeper prospects are yet to be probed especially Barails which may have oil too, in case the popular belief of pressure regression brought out froni the PIVT studies, comes true. The studies, duly corroborated by weilsite evidences and seismics-VSP/PIVT for pressure prediction, have been quite successful for the pore pressure evaluation in this region.
In the Schuppen belt (north-eastern part of Arunachal Pradesh) commercial production of oil is obtained from over pressure horizons of Mio-Pliocene age. Seismic and sonic log data, duly corroborated by the well site evidences, indicates very high pore pressure gradient up to 0.95 psi per ft in this area. Pressure reversal has also been observed in some of the structures isn the Tipams which may help in developing better porosities and likely to have good amount of exploitable reserves.
High abnormal to super pressures are observed from Middle-Lower Bhubans, practically in all the structures of the Cachar area with pressure gradient reaching to almost geostatic or even exceeding.
Compaction disequilibrium, aided partly by clay diagenesis has been responsible for generation of over pressures in Tripura area. However, in Cachar itnitial over pressuring took place due to compaction disequilibrium, subsequent major tectonic activity and uplifting of structures further intensified formation pressures. In the Schuppen belt of Assam and Arunachal Pradesh compaction disequilibrium as well as the tectonics has been responsible for generation of over pressures.
The decreasing pore pressure gradients below the over pressures zones of Miocene-Pliocene age, as evidenced by the pressures regression plots of seismic/VSP and interpreted PIVT data, should encourage exploration for deeper prospect especially in the structures in Tripura and Cachar adjoining Bangladesh where oil is reported in some of the fields.
P. 653
Sand Jet Perforating Revisited
Authors: Cobbett James S. 
Published: December 2007

Abstract
In 1995. joint venture oil companies started field operations in Lithuania, to complete development of small oil fields found in the west of the country (see Figure 1) during the Soviet era, but which had been considered as too small to develop for a country with giant oil fields to the cast. Wells, some of which had produced on test at over one thousand barrels per day, had been left with heavy mud across open perforations, often for more than a decade. When it proved impossible to get these wells to flow again using (western) tubing conveyed explosive perforators (TCPs). sand jetting was used, as has been the almost universal practice in Lithuania. The first well sand jet perforated by a joint venture company, which had yielded one barrel per day with (western) TCPs, gave one thousand barrels per day when perforated with sand jets.
Subsequently, one of the best producers in Lithuania, which had already been sand jetted once, was reperforated using more advanced techniques. Coiled tubing was run through the xmas tree and completion to enable the well to be sand jet perforated, with oil as the carrier fluid, under-balanced, with the well flowing throughout, resulting in a doubling of production to 800 BOPD. Sand jetting via coiled tubing using oil is being further developed and will be applied to other recompletions.
Though sand jet perforating is, al least theoretically, available from the main pumping contractors, it is almost unknown outside North America and the Former Soviet Union, the main technical references (Refs 1, 2, 3 and 4) being over thirty years old. Sand jet perforating does, however, provide a cost-effective means of passing deep formation damage and should form part of the armory of any practising petroleum engineer. This paper aims to remind engineers of this, review the technology and suggest appropriate applications.
Selection of Analytical Steam Stimulation Models Based on Common Reservoir
Authors: Robertson Eric P. 
Published: December 2007

Abstract
Correctly choosing an analytic steam stimulation model for forecasting oil recovery for any given reservoir is an important process of reservoir management. A model should accurately predict key project performance parameters such as oil/steam ratio, optimum cycle length, peak production, and cumulative oil production in order to be of real value. There are a number of different mathematical steam stimulation models available for use; each developed using different assumptions and geometries, and placing emphasis on different recovery mechanisms. The four models chosen for comparison against actual production from 11 different reservoir types located throughout the world are 1) Boberg and Lantz (1966), 2) Seba and Perry (1969), 3) Jones (1977), and 4) Gontijo and Aziz (1984). Each of the four models is described along with the input needed for each. A simple method that directs the engineer to the analytic model that most accurately predicts response from steam stimulation of a given reservoir is described. The percent average production error of a model when compared to actual field production was selected as the criterion for comparison of the models. The effectiveness of the models was found to depend on a grouping of common reservoir parameters called the "steam number." The steam number takes into account the reservoir parameters most affecting model output: reservoir pressure, permeability, crude oil gravity, and sand thickness. Reservoirs with a steam number greater than 1000 should use the Boberg-Lantz model, reservoirs with steam numbers between 10 and 1000 should use the Seba-Perry model, and reservoirs with steam numbers less than 10 will be best matched using the Gontijo-Aziz model. Although the Jones model did accurately predict response to some of the fields tested, it did not correlate well with the steam number. The Midway Sunset field in California, which was not part of the 11 original fields used to develop the selection procedure, was used to successfully test and verify the model selection method.
P. 49