bluuebunny/crossref_metadata_2025 huggingface dataset:
Pressure Transient Analysis In Bottom Water Drive Reservoir With Partial Completion
Authors: Tippie D.B. , Abbot W.A.
Published: December 2007

A study of a partially completed massive carbonate reservoir with a strong bottom water indicates that existing buildup theory does not adequately describe the flow system under producing conditions. Examination of field well producing conditions. Examination of field well test data using conventional transient radial analysis techniques and results from a single well radial simulation model show that flow geometry changes with time during the buildup period. Studies show that while spherical flow period. Studies show that while spherical flow initially exists during flow and shut-in periods, the system undergoes changes from spherical to hemispherical to linear vertical flow geometry. Permeabilities determined from radial buildup Permeabilities determined from radial buildup analysis do not agree with those determined from drawdown analysis because the flow geometry changes with shut-in time. The results of this study suggest that transmissibility, formation damage and permeability should be determined from drawdown tests which describe the flow system under producing operations. Flow nets are presented to illustrate flow geometry at various presented to illustrate flow geometry at various flow and shut-in times.

Introduction

A study of a partially completed massive carbonate reservoir with a strong bottom water drive indicates that existing buildup theory does not adequately describe the flow system under producing conditions. When partial completions producing conditions. When partial completions exist in a reservoir of this type, it will be shown that the flow geometry during the buildup period changes with time and that existing period changes with time and that existing buildup theory does not adequately describe the flow system under producing conditions. Failure to consider this phenomenon results in erroneous permeabilities and formation damage factors permeabilities and formation damage factors calculated from buildup curves by conventional techniques. This study indicates that drawdown testing should be used for calculating permeability and formation damage. Recognition permeability and formation damage. Recognition that the drawdown tests give more reliable values of permeability and formation damage than buildup tests may save a company considerable time and making performance predictions.
Physical and Numerical Simulations of Steamflooding in a Medium Crude Oil Reservoir, Lake Maracaibo, Venezuela
Authors: Ovalles Cesar , Angel Rico , Perez-Perez Alfredo , Hernandez Miguel , Guzman Nora , Anselmi Lorenzo , Manrique Eduardo
Published: December 2007

Physical and numerical simulations of steamflooding were carried out to determine the technical feasibility of applying this technology to a medium crude oil reservoir (25° API) located in the Lake Maracaibo, Western Venezuela, specifically, 3rd phase LL-03 reservoir. A one-dimension cell with steam injection (80% quality and 400 psi) was used to study the steamflooding behavior at laboratory scale. Oil rates cumulative oil productions and temperature profiles were reported and the results showed an increase of 14-20 percent of oil recovery with respect to original oil in place after waterflooding. Additionally, the use of steam drive as primary recovery method showed an additional of 5% in cumulative oil production. Compositional-thermal numerical simulations were carried out and validated using the laboratory scale results. Based on analysis of the crude oil true boiling point curve, the oil fraction was represented by a three pseudo-components model. The results (oil rates and cumulative oil productions) showed a reasonable match between the calculated and experimental simulations.

Using this model, a numerical simulation study was carried out in a seven-spot inverted pattern (300 m) in order to provide performance forecast and other useful information for the design, implementation and operation of a field scale steamflooding test. After seven-year of steamflooding, the simulation showed only 15 percent of incremental oil recovery in comparison with waterflooding. However, using a five-spot inverted pattern (100 m), 2.5-fold increase in cumulative oil production can be predicted with respect to waterflooding during the same period. Based on these results, it can be concluded that steamflooding technology in a Lake Maracaibo medium crude oil reservoir (25° API) represents a feasible alternative with high potential applications.
Experimental Study of Heavy Oil Production from Diatomite by Water Imbibition at Elevated Temperatures
Authors: Tang G. , Kovscek A. R.
Published: December 2007

Oil production from many fractured reservoirs is frustrated by not only low matrix permeability but also large oil viscosity and a matrix wettability state that is not sufficiently water wet to favor water imbibition. Some diatomaceous reservoirs, especially those containing heavier crude oil, appear to exhibit these attributes. Thermal recovery using hydraulically fractured wells is one process to improve oil recovery and unlock these heavier resources. Steam injection is typically carried out under saturated conditions and initial heating of a reservoir is accompanied by significant condensation and flow of the resulting hot water away from the injector. Thus, hot-water imbibition is an important component of thermal recovery in fractured, low permeability porous media.

This work presents the results from a series of spontaneous, counter-current water imbibition tests using outcrop diatomite cores (2 to 4 md) and reservoir diatomite cores (0.8 to 2 md). The experiments are isothermal and temperatures from 20 to 180°C are explored. Decane (nC10), two white mineral oils with differing viscosities, and heavy diatomite crude oil were all used as oil phases. At room temperature, oil-phase viscosities ranged from 0.9 to 6400 mPa-s. An X-ray computed tomography (CT) scanner, in combination with a high-temperature and high-pressure core holder, was used to visualize fluid movement and production of these oils. It is observed that temperature has a significant effect on water imbibition rate and residual oil saturation to spontaneous imbibition. In reservoir core filled with crude oil, the spontaneous oil recovery increased from 3% at 40°C (reservoir temperature) to more than 40% of oil in place at 180°C. The effect of temperature is to reduce oil-phase viscosity and increase water wetness of the rock. Finally, it is found that the experimental data scale according to dimensionless groups available in the literature. Inclusion of the mobility ratio as a function of temperature during scaling is necessary to collapse data.
How Artificial Intelligence Methods Can Forecast Oil Production
Authors: Weiss William W. , Balch Robert S. , Stubbs Bruce A.
Published: December 2007

The application of artificial intelligence tools such as fuzzy logic and neural networks is evolving as an oilfield technology. Log analysis work done in 1989 by Halliburton focused on applying backpropagation neural networks to identify total porosity and to identify lithofacies. In 1996 PRRC researchers used fuzzy logic to prioritize the significance of petrographic attributes to minipermeameter permeability measurements. Recently (2001), Zadeh Institute workers revisited the use of these tools in a manner consistent with soft computing terminology. In this paper, fuzzy ranking is used to prioritize inputs to neural networks that are trained, tested, and used to forecast oil production.

Patterns related to oil production are sometimes obvious in datasets from easy-to-interpret logs, but sometimes they are not, such as those in datasets from logs run through thin-bedded turbidite zones. The correlation between the individual log charts and core measurements varies from "good" to "bad" (fuzzy).

A neural network can be used to generate regressions when given the "good" log charts. The regression equations are developed with several log charts and core measurements and the resulting pseudo-logs are then correlated with known production. The resulting correlations can be used to estimate future oil production from potential producing wells.

Two field examples are used to demonstrate the fuzzy ranking technique and production forecasting correlations. The method to generate fuzzy curves is presented and sources of public domain neural networks are included in the references. The pitfalls involved in training and testing a neural network to predict oil production are also presented.
Conformance Improvement with Low Concentration Polymer Gels in a Heterogeneous, Multilayer Reservoir
Authors: Wouterlood C. J. , Falcigno E. D. , Gazzera C. E. , Norman C. A.
Published: December 2007

The Entre Lomas Block is located in the northeastern Neuquen Basin of Argentina. The Block, with an area of 742.5 Km2, is divided by the borders of Neuquen and Rio Negro provinces (Figure 1). The area includes two large anticlinal structures, Charco Bayo (CB) and Piedras Blancas (PB), that are productive from the Tordillo Formation.

The field, located approximately 90 kilometers north of Neuquén City, Argentina, was discovered in 1960. In 1975, secondary recovery operations began in the Charco Bayo structure.1 As of November 2001, the oil production rate of Tordillo Formation was 936 m3/d (5,887 bbl/d), with a cumulative produced crude oil volume of nearly 20 MMm3.

Due to reservoir heterogeneity and low permeability, cumulative oil production as of December 2001 was approximately 13.5 % of OOIP. Water channeling has been severe in most areas of the field, in spite of previous efforts to improve reservoir conformance with cement, aluminum silicate squeezes, and selective injection installations2.

In 1995, Petrolera Perez Companc S. A. (PPCSA) performed several high concentration, low volume injection well gel treatments. In 1999, further study indicated that lower concentration injection well gel treatments would be more appropriate in the Tordillo formation. This new gel treatment strategy was implemented in 1999/2000 in a group of injection wells. Certain marginally economic producing wells were also treated with higher polymer concentration gels. This paper describes the results of the 1999/2000 gel campaign.

As of November 30, 2001, PPCSA has quantified 585,800 barrels of incremental oil associated with the gel treatments, at a cumulative cost of approximately $2.22 per barrel. Incremental costs are expected to decline further as the oil response to the gel treatments reaches maturity.
Improved Oil Sweep through Discrete Fracture Network Modeling of Gel Injections in the South Oregon Basin Field, Wyoming
Authors: Dershowitz W. , Shuttle D. , Parney R.
Published: December 2007

Gel injection is used with water injection in fractured and heterogeneous reservoirs to decrease water production and improve the oil sweep efficiency. Gel treatments are able to achieve this because the gel is preferentially deposited to the most conductive fractures, blocking the water flow through those structures, and forcing to water to displace oil from the rock matrix instead.

This paper describes discrete fracture network (DFN) analyses and simulations of gel injection at the South Oregon Basin, Wyoming Phosphoria formation. These simulations were carried out to evaluate the efficacy of gel injection in improving water injection strategies.
The Mathematical Model of Non-Equilibrium Effects in Water-Oil Displacement
Authors: Barenblatt G. I. , Patzek T. W. , Silin D. B.
Published: December 2007

Forced oil-water displacement and spontaneous countercurrent imbibition are crucial mechanisms of secondary oil recovery. The classical mathematical models of these phenomena are based on the fundamental assumption that in both these unsteady flows a local phase equilibrium is reached in the vicinity of every point. Thus, the water and oil flows are locally redistributed over their flow paths similarly to steady flows. This assumption allowed the investigators to further assume that the relative phase permeabilities and the capillary pressure are universal functions of the local water saturation, which can be obtained from steady-state flow experiments. The last assumption leads to a mathematical model consisting of a closed system of equations for fluid flow properties (velocity, pressure) and water saturation. This model is currently used as a basis for predictions of water-oil displacement with numerical simulations.

However, at the water front in the water-oil displacement, as well as in capillary imbibition, the characteristic times of both processes are comparable with the times of redistribution of flow paths between oil and water. Therefore, the non-equilibrium effects should be taken into account. We present here a refined and extended mathematical model for the non-equilibrium two-phase (e.g., water-oil) flows. The basic problem formulation as well as the more specific equations are given, and the results of comparison with experiments are presented and discussed.
Application and Method Based On Artificial Intelligence for Selection of Structures and Screening of Technologies for Enhanced Oil Recovery
Authors: Ibatullin R. R. , Ibragimov N. G. , Khisamov R. S. , Podymov E. D. , Shutov A. A.
Published: December 2007

Main fields of the Republic of Tatarstan in Russia entered late stage of development. In recent years more than 60 methods on enhanced oil recovery and stimulation of producing wells have undergone comprehensive tests in a wide range of geologic conditions. Based on geologic information and experience of fields development there have been created geologic and hydrodynamic models for analysis and forecasting of technological indices of oil production, as well as data bases on application of methods for enhanced oil recovery and stimulation of wells.

Based on artificial intelligence, procedure is developed for selection of enhanced oil recovery method using model of residual reserves for different structures of development. Models apply neural network, capable to synthesize recommendations based on training by data base for realization of more than 60 methods on enhanced oil recovery and wells stimulation at similar structures of Tatarstan fields. These technologies are characterized by a set of criteria, including data on reservoir, formation fluids, operating conditions of wells, information on peculiarities of the technologies application. Models are trained on more than 2200 examples, reflecting correct conditions of realization of EOR and stimulation technologies, using considered technologies. During testing more than 70% of data sets are confidently recognized, which correspond to criteria of application of enhanced oil recovery methods, realized through injection wells, and more than 90% of methods on wells stimulation.

The developed procedure allows to forecast and rank the application of different methods for enhanced oil recovery and stimulation of wells at specific producing and injection wells in real-time operation mode. This procedure is used in conditions of fields development in the Republic of Tatarstan.

The conducted work allows to combine two modern approaches - modeling of field development and application of artificial intelligence for selection of most effective technologies on enhanced oil recovery and stimulation of wells. Data base has been developed for methods of enhanced oil recovery and stimulation of wells for conditions of Tatarstan fields.
Foam Generation in Porous Media
Authors: Gauglitz P. A. , Friedmann F. , Kam S. I. , Rossen W. R.
Published: December 2007

In steady gas-liquid flow in homogeneous porous media with surfactant present, there is often observed a critical injection velocity or pressure gradient ∇pmin at which "weak" or "coarse" foam is abruptly converted into "strong foam," with a reduction of one to two orders of magnitude in total mobility: i.e., "foam generation." Earlier research on foam generation is extended here with extensive data for a variety of porous media, permeabilities, gases (N2 and CO2), surfactants, and temperatures. For bead- and sandpacks, ∇pmin scales like (1/k), where k is permeability, over 2 ½ orders of magnitude in k; for consolidated media, the relation is more complex. For dense-CO2 foam, ∇pmin exists but can be less than 1 psi/ft. If pressure drop, rather than flow rates, is fixed, one observes an unstable regime between stable "strong" and "coarse" foam regimes; in the unstable regime ∇p is nonuniform in space or variable in time. Results are interpreted in terms of the theory of foam mobilization at a critical pressure gradient.
Further Development of the Pore Scale Mechanism of Relative Permeability Modification by Partially Hydrolysed Polyacrylamide
Authors: Singleton M. A. , Sorbie K. S. , Shields R. A.
Published: December 2007

One proposed method for the chemical control of produced water is by using a "relative permeability modifier" (RPM) which is usually based on a water soluble polymer. A considerable amount of literature on such materials has appeared although there is still not a complete consensus on the actual mechanism through which RPMs operate within a porous medium. One mechanism that has been suggested is based on the existence of an adsorbed polymer layer where this layer, within a water-wet porous medium, reduces water flow more significantly than oil. In this paper, we propose further developments of this adsorption mechanism of relative permeability modification. The present study is based on two complementary approaches as follows: (i) a series of detailed coreflood experiments has been performed to assess the impact that an adsorbed polymer layer has on the fluid flow pathways. Experimental results on tracer pulses, end point relative permeabilities/saturations and pressure profiles have been utilised in our analysis; (ii) a pore-scale network model has been developed which incorporates the proposed mechanism of RPM operation. The predictions from this model have then been compared with the experimental results. It has been possible to deduce that, not only is water flow affected more significantly than oil, but that the manner in which this occurs is different for each phase. The contributions to both the water and oil conductivity of relative permeability effects (due to saturation changes) and actual "pore blocking" is deduced.
Pore Microstructure and Fluid Distribution in a Diatomaceous Reservoir
Authors: Ross C. M. , Kovscek A. R.
Published: December 2007

This study was undertaken to improve our understanding of fluid distribution and flow behavior by quantifying pore type, pore body size, shape attributes, and throat sizes of pore networks in diatomaceous reservoir rock. This work is a first step toward providing a means of integrating different measurement types and establishing an interpretive tool for understanding laboratory results and field behavior. This project lays the groundwork for developing a predictive tool that can be utilized to generate input for reservoir simulator studies.

The pore microstructure of 11 diatomite samples from Lost Hills Field (Kern Co., CA) and one quarry sample was quantified using image analysis of photomicrographs collected with a Scanning Electron Microscope (SEM) in backscattered electron (BSE) mode. Six distinct pore types were identified ranging from small, irregularly shaped pores to large moldic and intraskeletal pores as well as large interconnected, intergranular pores. The throat size average and size range for each pore type was established by combining image analysis information with high-pressure mercury injection measurements. Once this relationship is determined, the pore body size and throat size serve as the basis for a predictive model allowing capillary pressure curves and fluid saturations to be calculated from pore type data.

In this study, the relationship between pore types, fluid flow, and fluid distribution indicate a dual porosity system. Permeability is primarily controlled by three pore types, which represent 1 to 28% of the total core porosity and 0.67 to 9.75% of the total volume. Fluid saturation models were developed to provide an accurate means of calculating oil and water saturations as well as their distribution within the pore network for both the reservoir and core samples. From the model, we found that the most permeable pore types have oil saturations that are 5 to 35% lower than reservoir saturations. This indicates that the oil is moveable and can be swept from permeable pore types. Alternatively, there was no net change in saturations for the remaining pore types between core- and log-derived saturations. For these pore types, spontaneous imbibition is the most likely production mechanism. The smallest pore type is predominately water filled with oil saturation values of about 32% in both the reservoir and core samples.

The proportion of each pore type can be predicted from wireline log data and used as input for the predictive capillary pressure model and fluid saturation models. This allows the models to be applied to the rest of the field providing data for field development decisions and simulator input.
Darcian Dynamics: A New Approach for the Mobilization of Ganglia in Porous Media
Authors: Amili Pouya , Yortsos Yanis C.
Published: December 2007

A number of problems in porous media involve the simultaneous flow of two immiscible fluids. As a result of the capillarity of the porous medium, however, the flow occurs in an intermittent way, in which phases may get trapped, immobilized, or conversely mobilized due to the flow of the other phase. This process of ganglia motion has been described in detailed past works by various authors using elaborate pore-network simulations. In this paper, we apply a different approach, in which all the hydrodynamic information of the flowing fluid and the effect of the various ganglia enters at the various ganglia interfaces using a boundary integral method. Methods of this type have been extensively used in potential theory, but have not been applied in the context of flow and mobilization of immiscible fluids in porous media. Their advantage is that the hydrodynamic problem is mapped at the ganglia interfaces and allows a fast and convenient way to describe the forces on the disconnected phase, the possible mobilization, stranding, coalescence, crowding effects, etc.

We present the method development by deriving the integral equation to be solved on the fluid interfaces. We then use a numerical method for its solution and examine a variety of problems including: the condition for the mobilization of a stranded ganglion as a function of the capillary number and the ganglion shape; its subsequent motion in the random capillary environment and the rate of stranding or coalescence; effects of gravity; and the interaction between neighboring ganglia. The latter does not always enter as a crowding effect, as intuitively expected. The method finds applications to problems where the flowing phase is disconnected, as for example in foamy oil flow or the countercurrent flow of steam-water in the presence of gravity.
Effect of Trapped Foam on Gas Tracer Diffusion in a Visual Microflow Model
Authors: Nguyen Quoc P. , Thissen Michiel H. G. , Zitha Pacelli L. J.
Published: December 2007

Foam (i.e., dispersion of gas in surfactant solution confined in porous media) is an excellent acid diversion and gas-blocking agent. In these and other applications, fluid flow control depends strongly on the ability of foam to enhance gas trapping. This was recognised long ago but the relation between gas trapping and flow reduction by foams is not well understood. Several authors proposed to use a tracer dispersion technique to quantify the amount of gas trapped in porous media during foam displacement. However, this technique may suffer limitations due to diffusion of tracer into the trapped foam. The purpose of this paper is twofold. (a) To check the validity of this technique, we study the resistance of one or more foam films to gas tracer mass transfer using our original method of ‘freely-standing’ film in a straight tube. (b) We estimate trapped gas saturation for several foam textures using visual micro-flow model experiments. Gas is injected into the model and its concentration is monitored at the outlet. The difference in tracer history between a dry model and a micromodel with foam placed inside is characteristic for the trapped gas fraction.
Multiple-Scale Stabilized Finite Elements for the Simulation of Tracer Injections and Waterflood
Authors: Ruben Juanes , Patzek Tadeusz W.
Published: December 2007

We present a numerical method for the simulation of misci- ble and immiscible multiphase flow in porous media, with emphasis on the advection-dominated case. A fractional flow formulation is adopted, resulting in a "pressure" equa- tion and a "saturation" equation. The key idea of the pro- posed methodology is a multiple scale decomposition of the variable of interest into resolved and unresolved scales. This acknowledges the presence of fine scales which can- not be captured by any grid, but whose influence on the coarse scales is not negligible. The multiscale approach leads to a stabilized finite element formulation, which pre- vents global spurious oscillations of the numerical solution without introducing excessive dissipation. The method is further improved by incorporating a novel shock-capturing technique based on a nonlinear dissipation mechanism pro- portional to the absolute value of the subscales. We be- lieve this approach is entirely new in the context of flow in porous media. Numerical simulations of tracer injection (miscible flow) and waterflood (immiscible flow) are presented. The proposed subgrid scale method with shock- capturing shows exceptional performance in all test cases studied. These test cases illustrate the potential and applicability of the proposed formulation for solving multiphase compositional flows in porous media.
Metering For Custody Transfer And Royalty Computations
Authors: Clausen R.E.
Published: December 2007

1961 Middle East Reg. Mtg. Dhahran, Mar. 27–29, 1961

The oil industry has been interested for many years in the use of meters for custody transfer and royalty computations rather than by the generally accepted practice of hand gaging of tanks. The reasons for the interest are; the savings of expenditures for installation of tankage, which in turn reduces evaporation losses; provides for more flexible and efficient operations, resulting from increased use of facilities such as tankage, pipelines and ship loading facilities by reducing waiting time necessary for manually taking opening and closing gages; labor savings in those cases where metering can be made automation and unattended. Another reason is the possibility that metering is more accurate than manual tank gaging, which benefits both parties where royalties are involved.

Prior to 1942, research on the accuracy of positive displacement meters was done by the American Society of Mechanical Engineers. Since then, guidance of research has been a joint venture by ASME and American Petroleum Institute committees. Standard methods were developed for design, research, testing and operation of meter measurement of liquid petroleum hydrocarbons by positive displacement meters. These methods were included in ASIDE publications, National Bureau of Standards Handbooks, the API Standard 1101 and other publications. Because of the need, about the year 1956, high capacity turbine type meters were developed and larger positive displacement meters were built. It is understood that because of the increasing use of turbine meters which are becoming more accurate, the API is changing the name of their "liquid positive displacement committee" to "liquid measurement committee."
Advance Drill Bit Designed For Minimum Cost Drilling
Authors: Sheshtawy A.A.
Published: December 2007

The Tri-Max* is a new bit developed after five years of research and field tests with the main objective of minimizing the drilling cost. The trade name Tri-Max stands for:–Maximum Footage–Maximum Rate of Penetration–Maximum Safety

The Tri-Max bit runs have achieved a 38% increase in the penetration rate compared to tricone bits of the same class.

The Tri-Max drill bit is completely different in configuration and performance from the tricone bit developed by H. R. Hughes in 1933, and still widely in use for oil well drilling. The Tri-Max bit's solid steel body's general configuration, when viewed from the side, is that of an inverted triangle with an upper full gage stabilizer section, intermediate taper section and a lower nose section. The patented cutting structure arrangement on patented cutting structure arrangement on the Tri-Max bit body will achieve self-advancing of the bit under reduced bit load compared to the conventional tricone bit, and hence ensure straight hole drilling. The transfer stress relief openings on the Tri-Max bit body encourage the rock failure by tension and shear, a process far more efficient than compression and shear, the rock failure mechanism inherent to conventional tricone and diamond drag bits.

Introduction

Drilling a deep oil or gas well is a fascinating and challenging job, but the optimization of the drilling operation in these deep wells is difficult to achieve due to the inherited weakness of the tricone bit, especially 8 1/2" in diameter or smaller. As the well gets deeper, and the formation becomes harder, the size of the hole becomes smaller, and with that, a tangible reduction of the tricone bit parts. At these depths, the friction between the drilling string and the hole increases, and the weight on bit and the tricone bit's cutting elements rotation at the bottom of the hole has a weak relation, if any, to what we observe and record at the surface. Consequently, most of the tricone bits run in deep exploration wells are more or less a trial and error experiment. In the last few years, the weakness of the tricone drill bit, especially for drilling deep wells, has been recognized by numerous individuals and organizations seriously involved in the drilling industry. The Tri-Max drill bit is a product of this effort.
Implementing Steam Assisted Gravity Drainage Through Combination of Vertical and Horizontal Wells in a Super-heavy Crude Reservoir with Top-Water
Authors: Gao Yongrong , Liu Shangqi , Zhang Yitang
Published: December 2007

Guantao formation in Du84 block, Liaohe oilfield is a typical massive block extra-heavy oil pool with top-water. The oil viscosity is very high and the formation thickness is great. Bitumen shell with 3~4m thickness exist between the top-water layer and oil column. If the bitumen is dissolved when heating in the steam injection recovery process, the top-water will flow down. Moreover, the field production showed that conventional steam stimulation recovery with vertical well is poor. New methods and technologies have to be researched and tested to improve the oil recovery, decrease operation cost and enhances economic efficiency.

Numerical simulation results showed that the reservoir can be developed efficiently by implementing Steam Assisted Gravity Drainage (SAGD) process using existing vertical well and horizontal wells to be drilled following steam stimulation. To avoiding top water going down, the new well completion methods have to apply, and the upper portion of the formation in the steam injector shouldn't be perforated. If the viscosity of the bitumen shell is greater than 500×104mPa.s, the 20m thickness of upper portion shouldn't be perforated to inhibit the top-water effectively. If the viscosity of the bitumen shell is 50~200×l04mPa.s, the thickness of upper portion not perforated should be more than 30m to inhibit the top-water effectively. At the same time, the results also showed that the heat communication between the wells is an important factor to control the top-water. The SAGD process can be implemented only when heat communication is established by steam stimulation in order to inhibit the top-water.
Feasible Evaluation of Natural Gas Floods in Wennan Low Permeability Reservoirs
Authors: Li M. , Hu Y. Q. , Zhao J. Z. , Huang Z. G. , Wu Y.
Published: December 2007

This presentation provides a technical overview of a project that evaluated the feasibility of natural gas injection in a Wennan low-permeability sandstone reservoir. An advantage of gas injection is high injectivity. Relative high injectivity combining with near miscible condition between injection gas and reservoir fluid offers a potentially attractive prospect in the Wennan low-permeability reservoir. Zhongyuan Oil Field and Southwest Petroleum Institute(SWPI) sponsored the project at Wennan field, including reservoir characterization, experiments, flow simulation, and nitrogen injection, which proved that a high gas injectivity and reservoir pressure was 44.35 MPa.

Main attention in this paper is paid to experimental research, including the regular PVT test. The slim-tube tests were used to determine minimum enriched gas composition(MMC) for miscible displacement at present reservoir pressure. The experiment was conducted at pressure 44.35 MPa and 393K. These slim-tube tests showed that a lean gas with reservoir fluids can reach near-miscible condition. Only a few LPG are needed to enrich the the lean gas.Then a set of experiments to quantify displacement efficiency and provide parameters for composition simulations.The first experiment evaluated the recovery efficiency in sandstone by enriched gas displacements, and the second looked at the recovery in sandstone by lean gas. These experiments showed the enriched gas breakthrough as 0.92HCPV in the typical miscible condition, final recovery to be 87.01%, and lean gas breakthrough(0.437HCPV) with recovery at 65.29%, as in immiscible displacement. However, substantial recovery after breaking(0.5HCPV with final recovery 85.29%) suggests an efficient extraction of intermediate components in the typical volatile oil. Additionally, the experiments in the project was

conducted to evaluate water flooding and WAG flooding. WAG flooding showed that WAG could significantly increase oil recovery, but the pressure difference would increase greatly when gas was injected. Therefore, WAG is not suggested in Wennan oilfield.

Further investigation was made at field with CMG 3D compositional simulation. Compositional simulation suggested slow breakthrough and high recovery at the Wennan field. These evaluations will lead to a pilot test in the Wennan low-permeability reservoir.
A Field Proven Analytical Method to Resolve the Open Hole Volume Gravel Packed in a High Angle or Horizontal Well, Enables Enhanced Pre-job Simulation.
Authors: Nelson Roy N. , Onwa Sam
Published: December 2007

This paper demonstrates an analytic approach to measuring the success of horizontal, open hole gravel pack completions. The approach is discussed using five UK North Sea case histories in which a post job evaluation was used to determine the percent of the open hole successfully gravel packed in each well. The method was verified in the field using radioactive tracer and / or temperature logs in three of the five wells with 3000 ft to 5000 ft horizontal open hole sections. The method closely estimates, without intervention, the actual Effective Open Hole Diameter, Deff, following drilling and hole clean-up operations. Using Deff, the observed Alpha Ratio, and an iterative match point technique, the actual lengths of the open hole gravel packed were computed. The method also corrected existing simulation procedures for calculating the volume of sand placed in the cased section above the sand control screens.

During the pre-job planning or simulation phase, an incorrect estimate of open hole diameter can result in erroneous estimates of transport velocity, dune height ratio, minimum pump rates required to avoid sand duning in the work string, the Alpha and Total Pack Time, and the sand and slurry volumes required. In addition, the relative success of the gravel pack could not be correctly measured, using previous methods where only the theoretical open hole diameter and measured sand slurry volume were known.

This proven Alpha Ratio analytical method provides an insight to the actual Effective Open Hole Diameter, enabling continuous improvement through enhanced pre-job simulation of subsequent project wells.
Calibrating Fracture Models with Direct Diagnostics: A Necessary but Humbling Experience
Authors: Lehman Lyle V. , Weijers Leen , Mayerhofer Michael , Wright Chris , Fisher Kevin , Davis Eric , Fulton Dwight
Published: December 2007

Although fracture models are predictive, and physical measurements are accurate, both require a certain level of scientific knowledge and training to interpret and execute correctly. Based on this understanding, if we can create fracture models that are highly accurate, we can make predictions more effective and valuable.

One technique makes modeling a more useful tool for designing, fine-tuning, and implementing fracturing treatments. Physical measurements of mini-fracture dimensions are input into a fracture model, allowing the model to more accurately reflect reality. After the model matches both the observed net pressure response and the directly measured hydraulic fracture geometry (the model is calibrated), the model can more closely predict the outcome of a main fracturing treatment. A survey of stimulation experts indicates that many think this step can more than double the value of using a model compared to simply using fluid-efficiency data. This paper discusses how physical measurements from a mini-frac treatment can be input into a fracturing model. Case histories will illustrate how decisions were made to alter fracturing designs and mitigate the risks associated with proppant placement.
Buffalo Redevelopment "The Wee Field That Grew"
Authors: Begg Paul D. , Krasey Russell S. , Lehto Doug A
Published: December 2007

During 2001 an intensive geophysical, geological and reservoir engineering, analysis was carried out on Nexen's 100% WI Buffalo Project located in the Bonaparte Basin. The work resulted in the successful drilling of two infill wells, during March / June 2002. The value, reserves and economic life of the Buffalo Project has been extended by 2 years with additional recovery of approximately 8 MMbbl.

This paper will review the original geologic / geophysical model and the non-unique nature of the Reservoir Engineering history match. The pre-stack depth migration [PSDM] work and results will then be described in detail, along with an explanation of the revised geologic model for Buffalo and how it changed our concept of the upside in the field. The reservoir simulation, decision tree, production forecasts and reserve summary will then be described.

The PSDM work indicated that the field is a tilted fault block, analogous to other fields in the Bonaparte Basin, instead of a rollover anticline. In the rollover anticline model, both original producers, Buffalo 3 and Buffalo 5, were located along the central crest of the anticline. The new tilted fault block model indicated both a "Northern Attic" and a "Western Attic". The infill drilling program was designed to drain the yet unswept attic oil at Buffalo.

Since Buffalo has a very strong water drive, typical reservoir simulation would not "see" the presence of the attics in the field, and the simulation results are not unique. Nexen had developed a comprehensive decision matrix, which reduced risk and created maximum flexibility. The Buffalo 7 well was critical to proving the new geologic model of the field. The well was drilled and completed in March-April 2002 and was followed Buffalo 8, Completed as Buffalo 9, in May-June 2002.

Nexen used a multi disciplinary team to review Buffalo, which has resulted in a successful project. Nexen has applied its expertise gained in Western Canada, the Gulf of Mexico and Yemen to its operations in Australia.

The successful redevelopment of Buffalo has increased reserves, extended productive life and increased the value of Buffalo to Nexen. The work has enhanced the companie's reputation in Australia as an operator with experience in both exploration and exploitation.
Improving Field Recovery, Sweep Efficiency through Optimizing Gas Injection / Gas Production in a Complex Mature Field
Authors: Naguib Mohamed , Hamdy Ahmed , Hussein Ahmed
Published: December 2007

The Zeit Bay field reservoir units consist of sandstone and carbonates, partially overlaying a tilted block of fracture 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. Over 70 development wells are actively depleting the reservoir.

The original oil leg was 850 ft-TVT. However currently the oil leg varies from 150 to 250. With this limited oil leg different problem arise. 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 (GI/GP) ratio results in a significant drop in production increase in wells water cut and reduction in the field sweep efficiency. In addition this decrease will hinder the gas cap expansion, this has lead to activate the aquifer water breakthrough.

The gas sweep being preferred because it's low residual oil. As the oil leg gets smaller, the production strategy is adjusted to maintain the dynamic equilibrium and increasing the (GI/GP) to enhance gas expansion which slow down water rise in the reservoir, control water cut in the wells and minimize residual oil.

The paper represents a case study of applying the gas injection to reduce the field decline from 30 to 14%, controlling water production and improve reservoir sweep efficiency.
A New Completion Method Triples the Productivity of Infill Wells on Mature Oilfield
Authors: Wang Yupu , Yan Yaru , Liu Bing , Wan Jun , Ning Shufeng
Published: December 2007

With the rapid progress of oilfield development technology, the new completion method is playing a more and more important role. A new completion technology not only opens formations, but it also improves permeability in formation as well. This paper discusses the optimized application of completion technology of adjustment wells at the later stage of high water-cut on mature oilfield. This method well controls the initial water-cut of infill adjustment wells, as well as improves the initial productivity of new wells.

The infill wells modification will encounter many problems in the mature oilfield, such as the horizontal variations between wells, the vertically difference of water content in fomations, the pressure difference distribution in space, and the scattering distribution of the to be modified. On the other hand, the formations are all that with permeability less than 0.01μm2. Completion technology is a key to make the productivity more efficient. This paper discusses about the fact that under the geological condition of continental sediment reservoirs with water-cut larger than 85%, after applying adequate completion technology, it triples the productivity of formations with permeability less than 0.01μm2, thus it makes a good economic result.
Pressure Transient Analysis in Fractured Produced Water Injection Wells
Authors: van den Hoek P. J.
Published: December 2007

It is well established within the Industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected -either for voidage replacement or disposal-large fractures may be induced over time. The current paper aims to provide a methodology for Injection Fall-Off (IFO) test analysis of fractured (produced) water injection wells. Some essential elements of IFO for fractured water injectors are: Closing fracture, (early) transient elliptical reservoir fluid flow, finite (changing) fracture conductivity, and fracture face skin.

An exact semi-analytical solution is presented to the fully transient elliptical fluid flow equation around a closing fracture with changing finite conductivity, fracture face skin, and multiple mobility zones in the reservoir surrounding the fracture. Based on this solution, type curves of the dimensionless bottom-hole pressure as a function of dimensionless time are provided covering both the period during fracture closure and the period after fracture closure. The shape of these type curves is studied as a function of the different relevant parameters, in particular the fracture closure time, fracture compliance, wellbore storage, fracture conductivity, fracture skin, mobility ratio, and injection period. The type curves are compared in detail with pressure transient (build-up/fall-off) behaviour known from the literature, particularly with the aim to identify the well-known "storage", "linear", "bilinear" and "radial" flow regimes.

Furthermore, based on the conceptual results presented in this paper, a number of different methods to determine fracture length from fall-off tests are discussed.

Finally, these concepts are applied to two field examples, where the dimensions of the induced fractures are derived from the analysis of the IFO data.
Development and Laboratory Verification of High Membrane Efficiency Water-Based Drilling Fluids with Oil-Based Drilling Fluid-Like Performance in Shale Stabilization
Authors: Tan C. P. , Wu Bailin , Mody Fersheed K. , Tare Uday A.
Published: December 2007

A major collaborative project was undertaken to develop novel environmentally acceptable water-based drilling fluids with high membrane efficiency to meet the future requirements of the petroleum industry. This paper describes various geomechanical considerations in the development and performance verification of the drilling fluids. Specialised test equipment, including a membrane efficiency screening equipment, an autonomous triaxial cell and a high pressure triaxial test equipment and associated test procedures, were either developed or modified for simulation of key drilling fluid-shale interaction mechanisms. More than 300 pressure transmission-chemical potential tests were performed on Pierre II shale samples to screen a wide range of novel chemical compounds for their membrane generation capacity in shales. Three of the compounds, which are capable of generating high membrane efficiency in the shale, were subsequently used to develop new generation water-based drilling fluids. Typical examples of the membrane efficiency screening tests conducted with novel compounds that generated highly and moderately efficient membranes are presented. The reasons for the difference in the membrane generation capacity of the compounds are discussed. The results demonstrate that the new generation water-based drilling fluids are capable of generating membrane efficiencies of between 55% and 85%. The shale stabilising capacity of the new generation drilling fluids developed was demonstrated and verified through a series of borehole collapse tests. Results of the borehole collapse tests are presented and discussed. The results clearly demonstrate the shale stabilising capacity of the new drilling fluids in comparison with the reference test which was not subjected to the mud pressure penetration and chemical potential stages with the drilling fluids.