bluuebunny/crossref_metadata_2025 huggingface dataset:
Strategy for Control of Water and Gas Cresting in a Thin Oil Column Using Horizontal
Authors: Shrivastava Vijay K. , Singhal Ashkok K. , Wang James J.
Published: December 2007

The exploitation of a thin oil column overlain by a large gas cap, and underlain by a huge aquifer by horizontal wells is challenging due to an early development of gas and water crests. This paper examines a strategy for alleviating the excessive production of gas and water by controlling the movement of fluid interfaces. This is achieved by withdrawing gas cap gas, and aquifer water, by means of separate horizontal completions, one each in the gas cap and in the aquifer, which are parallel and aligned with the oil zone completion. The gas cap gas, aquifer water, and oil are produced through separate strings. The high-pressure gas can be sold or utilized, and the produced water can be disposed of at the surface or subsurface.

The simulation results indicate an increase in the oil reserves to the extent of 25–50% over a conventional horizontal well for different ratios of vertical to horizontal permeability, over a 5 years period. The proposed system offers a relatively easy effluent handling, and sustained production of normal GOR, low water-cut oil for a longer duration of time. Proper well steering, completion, and its maintenance are identified as keys to the economic success of the strategy

P. 413
Optimization of Water Injection in a Sandstone Reservoir: A Successful Case Study
Authors: Ahmed A. Elias , Murthy R.V.S. , Bharkatya D.K. , Sengupta T.K.
Published: December 2007

Steps taken for a speedy evaluation for successful optimization of water pattern by detailed reservoir characterization, is discussed with reference to an Eocene sandstone reservoir of Kalol field India. The reservoir without water aquifer support has 30 years of production history. Water injection was done for 25 years in a central line drive consisting 8 injectors aligned in N-S direction. The main production problem was the rapid decline in reservoir pressure in the main pool, from 237 to 77 Kg/cm2 for a production of 25% OOIP. Performance reviews carried out in 1981, 1982 and 1990 suggested various steps such as increase in water injection rates, switching to peripheral injection besides central line drive and infill drilling to arrest the decline in reservoir pressure but without success. Integrated genetic facies modeling done in 1992, suggested reduction of the amount and redistribution of water throughout the fiel away from the most permeable parts. This has improved the production performance after 25 years by way of arrest of pressure decline.

P. 465
Effect of Drainage Area and Producing Rate on Horizontal-Well Oil Recovery in Bottom
Authors: Permadi P.
Published: December 2007

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

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

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

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

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.

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

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

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

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

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

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

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
Implementation of Waterflood in Joffre Viking I Pool
Authors: Coskuner Gokhan , Bamsey Al , Stanton Micheal
Published: December 2007

The Joffre Viking I Pool was discovered in 1994 in central Alberta. Since discovery some fifty wells drilled on 64 ha (160 acre) well spacing have delineated the reservoir covering an area of approximately 38 km2. The pay zone is a marine bar sand with a thickness of up to 1.3 m and a porosity of up to 17%. The permeability of the formation ranges from 1 to 10,000 md) with the average being above 500 md in the better parts of the pool. The reservoir contains a slightly undersaturated 41.5 API oil having an initial discovery pressure of 10,367 kPa. The production mechanism is solution gas drive.

The average pressure of the pool had declined to approximately 5200 kPa by October 1996 accompanied with ever increasing produced gas oil ratios (GOR) as a result of liberated solution gas. The declining productivity and increasing GOR lead Blue Range Resource Corporation (BRRC) to consider implementing a waterflood operation to maintain the pressure in the pool while mobilizing additional oil.

This paper describes the results of a numerical simulation study conducted on the Joffre Viking I pool. The numerical model was used to history match the past behaviour of the field and to predict the future performance for depletion drive and various waterflooding scenarios. It has been found that the ultimate recovery from the field can be increased by more than a factor of two through waterflooding while maintaining the reservoir pressure. Encouraged by the results of the numerical simulation study, a waterflood has been implemented in the field. The initial field response is presented in the paper. A comparison between the predicted response and the actual field response is made and the differences are discussed.

P. 79
A Comparison of Forecast and Actual Production after a Decade of Field Operations in
Authors: Brady C.L. , Lee L.P. , Lee S.K.
Published: December 2007

The Alpha Unit (Table 1) produces from the Minnelusa formation at an average depth around 7600 ft. Alpha, discovered in 1987, was the largest oil discovery in Wyoming for that year. Developed on 40-acre spacing, primary reserves from nine producing wells was expected to yield 1.4 MMBO. Implementation of a three-stage polymer-augmented waterflood, very similar to the programs implemented by Sloat, showed the potential of an additional 4.5 MMBO. Laboratory studies of cores, injection water, and reservoir fluids, gave guidance to formulating the injection program. Mack and Duvall's evaluation of this type of injection strategy at other Minnelusa floods served as a check for expectations at Alpha. This paper documents the data and forecasting techniques used at Alpha and compares forecast production to actual production obtained.

P. 123
Water Shutoff Treatments in Eastern Alberta: Doubling Oil Produciton, Decreasing
Authors: Samari E. , Scott D.L.T. , Dalrymple D.
Published: December 2007

Poor primary cement jobs in the Provost area of eastern Alberta, Canada, have resulted in approximately 200 wells being classified as economically marginal. The inadequate cement bonding in these wells has caused the channeling of water from the formation below (as in Dina "C," Fig. 1). Analysis of the production data supported the thesis that channeling was the principal reason for the increase in water production. In 90% of the cases observed, it was 1 to 6 months before the water cut rose from the initial level of 0 to 10% to as high as 98%; in many cases, this increase occurred immediately after the primary completion of the well. Cement-evaluation logs that were run on a number of candidate wells confirmed that channeling of water was the cause of the sudden increase in water cut.

The producing formation is the Cummings sandstone, which was deposited in the early Cretaceous era. The average porosity in this field is 28%, with a permeability range of 200 to 3,000 md and an API crude gravity of 21.60. Bottomhole pressures and temperatures range from 4,500 kPa to 5,500 kPa, and from 27 C to 30 C, respectively. The depth in the 25 candidates ranges from 750 m to 1000 m, and the average water cut before treatment was 98%.

Previous attempts to control water production by using a silicate-based polymer slurry and Class-G cement had met with limited success. These treatments had logged an average success rate of 40%. An improved treatment design was proposed: a silicate-based polymer slurry followed by an ultrafine cement blend to assist in sealing the channel permanently. If necessary, a Class-G cement blend would follow to ensure the success of the cement squeeze.

The following criteria were used to evaluate the relative success of each treatment:

The equivalent of 4 m3/D of incremental oil production was sustained for a minum of 100 days to achieve a payout for the treatment (=﹩40,000 CDN) at a net selling price of ﹩100 CDN/m3 of oil.

Water cut was decreased by at least 15%.

Savings were accrued as a result of decreased water production. Although this cost is minimal, the impact on treatment plants running at maximum capacity can be quite significant.

The treatments resulted in an incremental increase of 104 m3/D of oil initially and a decrease in water production from 3,927 m3/D to 63 m3/D. The project started in July 1996, and the last of the candidate wells was treated the following December. According to the production numbers of February 1997, the treated wells were producing an incremental 78.8 m3/D of oil, and 674.7 m3/D of water. The overall success rate of these water shut-off treatments rose to 75%, in contrast to the previous 40% success figure.

P. 153
Unconventional Miscible EOR Experience at Prudhoe Bay
Authors: McGuire P.L. , Redman R.S. , Mathews W.L. , Carhart S.R.
Published: December 2007

This paper summarizes the conceptual development, reservoir simulation, and field testing of a new miscible EOR recovery process at Prudhoe Bay. Two distinct variations of this process have been evaluated.

The vertical Miscible Injectant Stimulation Treatment (MIST) process involves completing a production well at the bottom of a thick, continuous, watered-out interval. A large slug of miscible injectant (MI) is injected, followed by a small slug of chase water. The MI sweeps rock not contacted by previous MI injection and drives EOR oil to offset producers. It also creates a mobilized oil bank in the vicinity of the production well. The well is then recompleted at the top of the reservoir and returned to production service.

It is particularly advantageous to utilize this vertical drive process in conjunction with horizontal wellbores. In the lateral MIST process, a horizontal lateral is drilled along the base of the reservoir from either a production or injection well. MI is injected sequentially into several intervals along the lateral to mobilize EOR oil from previously unswept areas. The lateral well is then returned to normal production or injection service.

Simulation data indicate that the vertical MIST process could recover over 200 Mstb of incremental oil per well at initial rates of up to 1000 stb/D. Calculations for the lateral MIST process indicate potential recovery of more than a million barrels of incremental EOR per lateral.

Field results have been mixed, but are encouraging. The vertical well MIST showed litfie response, but it did provide valuable insight into the performance of the MIST process. Incremental EOR from the three MIST lateral wells is over 1.3 MMstb, with current rates of about 4000 stb/D.

P. 249
Effects of Polymer Adsorption and Flow Behavior on Two-Phase Flow in Porous
Authors: Zheng C.G. , Gall B.L. , Gao H.W. , Miller A.E. , Bryant R.S.
Published: December 2007

To determine the effect of water-soluble polyacrylamide polymer adsorption and flow behavior on oil recovery, both steady-state and unsteady-state flow experiments were performed on Berea sandstone and reservoir cores. Berea sandstone core is strongly water-wet while the reservoir core is mildly oil-wet. Relative permeability curves and polymer adsorption measurements were made at residual oil saturation and 100% water saturation for increasing polymer concentrations. Mobility measurements were made at different polymer concentrations and shear rates.

A selective reduction of the relative permeability to water with respect to the relative permeability to oil was observed for both Berea and reservoir sandstone cores. The reduction of the relative permeability to water in the presence of oil phase is more than that at 100% water saturation. As polymer concentration increases, polymer adsorption, irreducible water saturation and relative permeability reduction increase. Residual oil saturation remains almost the same. Wettability is beneficial to water-soluble polymer adsorption. In reservoir core, relative permeability reduction could be attributed to both wettability change and pore-size restriction. Polymer adsorption isotherm follows Langmuir's law. Relative permeability reduction as a function of polymer adsorption exhibits an "S-type" curve. It increases exponentially as polymer adsorption increases and eventually approaches a constant. An empirical model was proposed to correlate this characteristics.

As predicted by the depletion layer and viscoelasticity theories, flow behavior of polymer solution in porous media is found to be significantly different from that in bulk solutions. A modification was made to the existing shear rate model based on mobility measurements, showing that the depletion layer effect is in direct proportion to polymer concentration, and is more significant in the reservoir core than in Berea core.

New models were incorporated in UTCHEM, a chemical flood simulator developed by the University of Texas. These models can provide more accurate prediction of the combined effects of relative permeability reduction and viscosity over existing models. Case studies show that the long-lasting relative permeability reduction by polymer adsorption is likely to maximize the benefits of polymer solution in polymer flooding. Increased understanding through simulation may lead to improved field profile modification and near wellbore treatments. The effects of cross-flow and the degree of relative permeability reduction are two critical factors to determine polymer placement strategies and success.

P. 293
Mechanistic Study of Disproportionate Permeability Reduction
Authors: Nilsson S. , Stavland A. , Jonsbraten H.C.
Published: December 2007

It is a common observation that gels in a porous media reduce the permeability to water more than that of oil. Core floods on sand packs using well defined model media has been carried Out to elucidate the matter.

Three different packing materials have been used, acid cleaned quartz sand, Teflon powder and a mixture of quartz and Teflon. Quartz is strongly water-wet and Teflon is oil- wetting. The use of model media gives a good control of wettability effects. The systems used are:HPAM based polymer with an added crosslinker orbiopolymer.

The brine is synthetic sea water and the oil is a white oil.

The results show that the disproportionate permeability reduction (DPR) effect can be interpreted by a mechanism with segregated pathways for oil and water. In a porous media preferred pathways for oil and water are governed by the wettability and to some extent the pore size. A water based gelant will flow in the water preferred pathways and block these channels. The largest DPR effect is observed in mixed wetting media where the difference between oil preferred and water preferred pathways is enhanced compared to homogeneous wetting media. The oil saturation at which the gelant is placed has also been shown to be of importance. Decreasing the oil saturation at which the gelant is placed gives a stronger permeability reduction towards both phases.

P. 335
Horizontal Wells in the Algyo Field, Hungary-Evaluation of a Successful IOR Project
Authors: Palasthy G. , Pipicz V. , Munkacsi I. , Tromboczky S.
Published: December 2007

Compensation of the decreasing domestic recoverable reserves can be supported by further development of existing, producing fields in addition to successful exploration. Along with the application of different EOR methods, considerable results can be achieved by horizontal wells. With the application of this technology, the hydrocarbons which seemed to be hidden in unreacheable parts of the reservoirs become economically extractable reserves increasing the value of the field.

The first horizontal well in Hungary was drilled in 1989 and thereafter 32 horizontal sections were established. The 70% of these wells are in the Algyo field. In this field, the Alsopannon-l3 reservoir should be stressed, where 12 oil and 3 gas producing wells were kicked off for horizontal sections in the period of 1993/97. The successful results highlighted that this technology can be applied in the case of mature fields on the one hand, and, on the other hand gave momentum to the application of the method in a wider spectrum in this field. The findings and experiences achieved by horizontal wells in the Algyo field are summarized in this paper.

P. 407
Improved Field Recovery by Controlling Gas Production in Hetrogenous Gas Injection
Authors: Hiekal Salah A. , Kamal Mohamed , Mosseir Mohamed
Published: December 2007

The Zeit Bay field reservoir units consist of sandstone and carbonates, partially overlaying a tilted block of fractured basement reservoir with a complex drive mechanism. A secondary recovery scheme of gas re-injection into the original gas cap was initiated to maintain reservoir energy and minimize pressure decline. About 45 development wells are actively depleting the reservoir. The original oil leg was 850 ft TVT, but now the oil leg varies from 50 to 200 ft TVT. With this limited oil leg, different problems arose. The most serious problem was the increase in gas production, that resulted in a decrease in gas injection to gas production ratio (GI/GP). The decrease in the Gl/GP ratio results in a fast field decline rate that reflects negatively on the field sweep efficiency. In addition this decrease will hinder the gas cap expansion, and hence will give chance to premature water breakthrough. These problems were treated and controlled by the following measures:Drilling new infill wells horizontally, with a sufficient stand off from the GOC. The last well drilled horizontally in the Sandstone formation of Zeit Bay field produced about 2500 bopd with a productivity index of about 500 bbl/day/psi.Controlling the gas production from high GOR wells. More than 5 wells were classified as high gas oil ratio wells producing at 7000 scf/bbl or more. The intensive gas production was controlled in these wells using one or more of the following procedures:Shut down policy that includes both field and individual wells.Workover plans which include chemical gas shut off using polymer injection into channels behind the casing or mechanically using straddle Packer and cemented casing liner. Accordingly, these high gas wells have acquired a sharp decrease in their GOR, which helps in saving the reservoir energy.

Currently the 5 wells produce under gas lift assistance with very low GOR, thus saving more than 30 MMSCF/D of the previously produced gas, and increasing the field oil production plateau by about 3000 bopd. In addition, the GI/Gp ratio increased from 60% to 80% resulting in a better sweep efficiency and decreasing the annual field decline from 30% to 14%.

P. 423
Improved Surfactant-Alternating-Gas Foam Process to Control Gravity Override
Authors: Shi J-X. , Rossen W.R.
Published: December 2007

Gravity override in foam mobility-control processes results from the competition between lateral pressure gradient and gravity. Therefore, overcoming gravity override with continuous foam injection requires raising injection-well pressure, possibly risking fracturing the formation. Foam processes employing surfactant-alternating-gas (SAG) injection at a fixed injection-well pressure, however, can overcome gravity override without excessive injection pressures. This advantage applies even in radial flow, where declining flow rates at increasing distance from the well make gravity effects especially intractable. This advantage does not apply to processes with continuous foam injection or SAG injection at fixed injection rate. Moreover, this advantage of constant- pressure SAG foam processes appears to be relatively insensitive to the details of foam behavior. In such a process, injection rate increases as foam dries out near the well and injectivity increases; as a result, most of the fixed pressure drop between wells is focused on the displacement front, with maximum suppression of gravity effects. We illustrate these effects with numerical simulations of foam displacements in 2D homogeneous rectangular alid cylindrical reservoirs.

Simulations of SAG foam processes are exceptionally sensitive to numerical artifacts. Earlier work in this area was affected by these artifacts. Some of the artifacts, and ways to control them, are discussed.

P. 491
Restriction of Gas Coning by a Novel Gel/ Foam Technique
Authors: Lakatos I. , Lakatos-Szabo J. , Kosztin B. , Palasthy Gy
Published: December 2007

The laboratory and field studies were focused on development of a well treatment technology which can be used for restriction of gas coning in the Algyo reservoir. The method is based on simultaneous placement of a polymer/silicate gel at the GOC and a supporting foam pillow into the oil bearing layer. Extensive laboratory studies were carried out to tailor the chemical system to the field conditions. Use of short chain alcohol and natural protein as additives improved the efficiency of chemical mechanism. Special attention was paid to implementation of the technology. Two-point injection regime was elaborated to develop a horizontal barrier between the oil and gas bearing zones. The field test resulted only in a partial success: the hydrodynamic measurement definitely shown that the barrier was correctly placed, the oil flow in the pay zone was not effected, the GOR temporarily improved and the WOR positively changed. The long-term observations are, however, discourages: the investment and the return rate of expenditure is not balanced. The Hungarian experts take a stand on extending the observation period for more cycles and to collect abundant arguments to continue or to suspend the R&D activities and the field projects.

P. 491
A Dynamic Pore-Scale Model of Imbibition
Authors: Mogensen Kristian , Stenby Erling
Published: December 2007

We present a dynamic pore-scale network model of imbibition, capable of calculating residual oil saturation for any given capillary number, viscosity ratio, contact angle and aspect ratio. Our goal is not to predict the outcome of core floods, but rather to perform a sensitivity analysis of the above-mentioned parameters, except the viscosity ratio. We find that contact angle, aspect ratio and capillary number all have a significant influence on the competition between piston-like advance, leading to high recovery, and snap-off, causing oil entrapment. Due to enormous CPU-time requirements we could not incorporate long-range correlations among pore and throat sizes in our network, but were limited to small-range correlations. Consequently, the gradual suppression of snap-off occurs within one order of magnitude of the capillary number. At capillary numbers around 10- to 10-, snap-off has been entirely inhibited, in agreement with results obtained by Blunt using a quasi-static model. For higher aspect ratios, the effect of rate and contact angle is more pronounced. Many core floods are conducted at capillary numbers in the range 10 to 10.6. We believe that the excellent recoveries observed during our waterfloods on tight chalk may be explained by the combined effect of rate, non-zero contact angle and existence of long-range correlations. Vast reductions in residual oil saturations are largely due to suppression of snap- off in favour of frontal displacement, whereas ganglion mobilization plays a much more modest role in the displacement of continuous oil.

P. 47
Effects of Variables on Microbial Profile Modification with Spores
Authors: Ok Lee Hae , Bae Jae H.
Published: December 2007

A microbial profile modification process consisting of sequential injection of spores and nutrient was reported previously. Variables affecting the efficacy of this process was studied using test-tube tests and corefloods in Berea and reservoir cores. It was found that a certain spore suspension concentration of about 107 cfu/mL is needed for effective spore propagation and plugging efficiency. A salinity above 2 wt% NaCl is needed for Salton-1 for increased permeability reduction and the time needed to achieve it. Higher injection rates, pH, and the presence of crude oil affect the degree of permeability reduction and biofilm stability. It is concluded that permeability reduction could be controlled to a significant degree by a judicious selection of nutrient package and injection scheme involving spore and nutrient concentration and amount.

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