bluuebunny/crossref_metadata_2025 huggingface dataset:
Coaxing Information from Petrophysics and Integrated Data Analysis: The Menggala South Field Case History, Sumatra, Indonesia
Authors: Pederson John M. , Stewart William F. , Yuwono Ipung P.
Published: December 2007

We developed a reservoir model for potential infill locations in this mature oil field. Prior to a 3D seismic survey expected recovery was over 60% and the field had a limited amount of reserves based on the old 2D seismic lines. The new seismic study showed the crest of the structure was missed during the initial field development. This study was commenced to delineate new well locations and determine if one or more horizontal wells were feasible.

This study consisted of revising the petrophysics data from 11 wells, building an earth model and making a simple simulation model. The field had wells drilled over a fifteen year period from 1972 to 1987. This paper outlines the efforts to obtain a usable log suite including permeability, Swi and Sorw. Information from nearby fields and the initial field simulation using average properties were included in this analysis. This information was included into the earth model and subsequently the simulation model.
Successful Application of ESP's in a Very Corrosive Environment, Gulf of Suez Area, Egypt (Case Study)
Authors: Naguib Mohamed , Iraki Hesham , Wilson Magued , Hussein Ahmed
Published: December 2007

The need for artificial lift is very common worldwide, nearly all reservoirs requires artificial lift at a certain stage of the field life. The decision of which artificial lift method to use is very important to the long-term profitability of the field. An improper decision of artificial lift can reduce production and increase the operating costs substantially. Once a decision has been made on the type to install on a well, it can rarely be altered whatever the method been selected.

Ras Fanar Field is located on the western side of the central part of the Gulf of Suez about 3 km east of the city of Ras Gharib. Production commenced in January 1984 and a peak production rate of 20 MSTB/D was achieved in May 1984. The field was produced naturally for 14 years and the produced fluid contains up to 15% H2S and 11 % Co2 in the associated gas phase.

It has been recognized that there is a need for artificial lift when water cuts increased and/or reservoir pressure decline. Studies carried out by SUCO concluded that ESP's are the most appropriate method and it was installed in 1996. The operating experience gained during the period 1996 to 1998 led to significant improvements, resulting in ESP run lives in excess of three years. The main problems during the initial phase of the project and the applied solutions, as well as critical operating factors will be described.

This paper presents and discusses the operational challenges of the ESP in such highly aggressive environment and documents the success and failures.
A Study of Wettability and Permeability Change Caused by Adsorption of Nanometer Structured Polysilicon on the Surface of Porous Media
Authors: Binshan Ju , Shugao Dai , Zhian Luan , Tiangao Zhu , Xiantao Su , Xiaofeng Qiu
Published: December 2007

A nanometer (10−9m) structured particle material, generally so defined that the diameter of the particle is no more than 100nm, has some special physical efficacy in its surface, small size and other properties. One kind of polysilicon with sizes ranging from 10~500nm, and considered as nanometer or sub nanometer sized powder, was used in oilfields to enhance water injection by changing wettability of porous media. The mechanism of enhancing water injection is through improving relative permeability of the water-phase by changing wettability induced by adsorption of polysilicon on the porous surface of sandstone. On the other hand, the adsorption on the porous surface and plugging at the small pore throats of the polysilicon may lead to reduction in porosity and absolute permeability (K) of porous media for pore sizes from 100 to 1000,000nm. Thus the degree of success in well treatment is determined by the improvement of effective permeability of the water-phase.

In this paper a mathematical model, which was combined with the study of experiments in the laboratory, is presented and a simulator is developed to simulate water injection dynamics under the conditions of polysilicon injection. The simulator can accurately simulate the process of migration and adsorption in the pore bodies and blocking at the pore throat of the polysilicon in the sandstone. A series of numerical simulation runs was conducted to study the effect of a wide range of parameters, such as the sandstone with different permeabilities, concentration of the polysilicon, injection volumes, and others. The effective permeabilities of the waterphase measured by a number of core flooding experiments are matched well by the numerical results. Since April 2000, nine well treatments with solvent slugs of suspended polysilicon particles in several oilfields in China was shown to be successful and the average injection rate increased 5 times after treatments.
Determination of Fracture Orientation by Multi-Well Interference Testing
Authors: Cherifi Mohamed , Tiab Djebbar , Escobar Freddy H.
Published: December 2007

It is often desirable to know patterns created after a number of wells in reservoir have been fractured. Interference testing is one of the best techniques that can be used for estimating some of the important formation properties (transmissibility and storativity) and fracture orientation.

Generalized correlations are presented relating (a) the dimensionless pressure response, PD, inter, at the intersection point of the pressure and the pressure derivative to the compass orientation, θ, and (b) the quotient of the dimensionless pressure and the ratio of dimensionless time to the square of the dimensionless radial distance, (tD/rD2)inter, at the intersection point to the compass orientation.

The correlations can be used for analyzing interference test pressure response at an unfractured shut-in well caused by a production of a vertically fractured well with a uniform flux, infinite or finite conductivity fracture provided that the half fracture length is known a priori.

Detailed procedures for the analysis of interference testing of a vertically fractured well are presented and demostrated through a simulated example.
Waterflooding Performance of Stratified Reservoirs with Bottom-Water Conditions
Authors: Shirif Ezeddin , Zao Gary
Published: December 2007

Many reservoirs in North America contain a high water saturation zone "bottom-water" underlying the oil zone. Waterflooding under such conditions is typically ineffective because of chanelling of water through the bottom-water zone. However, in some cases, waterflooding such reservoirs may still be feasible and economically viable. While there is no doubt that some of the injected water bypasses the oil zone through the bottom-water zone, most of the injected water may still displace the oil, depending on the reservoir conditions. Therefore, a mechanistic understanding of oil displacement by a waterflood in the presence of a bottom-water zone is the basis for predicting recovery performance, and there is a need for developing a mathematical model to describe water channeling under bottom-water conditions.

In this paper, a new simple analytical model was developed to predict waterflood performance in stratified reservoirs when a water zone is present. Given the reservoir description, the new mathematical model can be used to describe the amount of water channeling into the bottom-water, calculate pressure distribution in each layer and together with a prediction of oil recovery. Results of the mathematical predictions are compared with experimental and simulation results, showing good agreement.
The Geological Application of Acoustic Images in Homogeneous Clastic Sediments; Examples from the Tertiary Hemlock Formation, Cook Inlet, Alaska
Authors: Johansson M. , Saltmarsh Art
Published: December 2007

The Cook Inlet is a major oil and gas province south-southwest of Anchorage, Alaska. It is located in a forearc basin setting, which developed as a result of plate motion. This plate motion caused the migration and accretion of the Chugach terrain. The overall tectonic regime is compressional with the principal maximum stress orientated northwest to southeast. Thirty thousand feet of Tertiary sediments occupy the basin, and this great thickness is a result of contemporaneous deposition and active tectonics.

The Hemlock formation is nonmarine in origin and comprises sandstone and conglomerates of Eocene and Oligocene age. The rocks include braided stream deposits, alluvial fans shed from the margins, and fluvial deposits that developed in the axis of the basin. The sandstones and conglomerate beds often stack to form large homogenous sedimentary units, which can reach thicknesses greater than 50 ft.

An acoustic imaging tool commonly used in wells drilled with oil-based mud or other highly resistive drilling fluids has been used in the evaluation of this formation. Homogenous rocks have acoustic properties similar to these fluids, resulting in the resolution of very little diagenetic detail. However, dipping surfaces and textural variations were observed on the image and these features contributed to the building of a sedimentological model. Additionally, borehole breakout orientation provided key information regarding borehole stress directions.
A Chemo-poroelastic Solution for Stress and Pore Pressure Distribution around a Wellbore in Transversely Isotropic Shale
Authors: Ghassemi A. , Diek A.
Published: December 2007

It is generally accepted that shale deterioration and borehole instability are significantly influenced by excessive pore pressure, ion exchange between drilling fluids and shale, and the anisotropy of the in-situ stress state as well as the formation. This paper describes a model for estimating the influence of elastic and chemo-mechanical anisotropy on the distribution of stress and pore pressure around a well in transversely isotropic shale. The model is based on a practical theory that couples ion diffusion, chemical osmosis, and hydraulic flow to stresses and pore pressure. The field equations of the model are derived within the framework of a continuum chemoporoelastic theory that linearly relates total stresses and variation of fluid content to the strains, pore pressure, and solute mass fraction through anisotropic material coefficients. The field equations are solved analytically for the problem of a wellbore in transversely isotropic shale to yield the solute mass fraction, pore pressure, and the stress distributions around the borehole. The solution has been applied to a typical field situation and the results indicate that the osmotic pressure tends to stabilize the borehole. However, osmotic pressure dissipates with time due to ion diffusion. Furthermore, it is found that the anisotropy in chemo-mechanical material coefficients strongly affects the effective stresses around the borehole and enhances the potential for borehole failure.
A Damage Mechanics Approach for the Modelling of Sand Production in Heavy Oil Reservoirs
Authors: Shao J. F. , Marchina P.
Published: December 2007

Allowing sand to be produced together with the oil is a field proven technique to economically produce heavy oil reservoirs. By doing this, the performance of the wells is increased owing to a number of factors including an increased near wellbore permeability and/or the development of cavities (wormholes) significantly improving the flow conditions in the reservoir. However, the combination of a limited understanding of the physically complex processes involved in this phenomenon and the economic drive to adopt a pragmatic approach has led to mixed rate of success for this type of projects.

One of the first issue to tackle in studying this phenomenon is the quantification of the sand production and, equally important, the impact it has on the well and reservoir behavior.

Building on already published work, a sand production model is proposed that accounts for the mechanical damage induced in the formation by the production of sand. This model has been deliberately kept simple to evaluate the potential of the approach for modelling sand production in heavy oil reservoirs. The framework of the model is that of elasto-plasticity including isotropic damage. Th emodel has been tested on a synhetic, though realistic, set of data and, despite the simplfying assumptions (single phase flow, constant fluid viscosity) could qualitatively reproduce the salient features of the behaviour of typical heavy oil wells.
Quantifying Rock Capillary Strength Behavior in Unconsolidated Sandstones
Authors: Han G. , Dusseault M. B. , Cook J.
Published: December 2007

Changes in water saturation or rock wettability can lead to rock instability and sand production. The effects of saturation on rock strength have two origins - chemical sensitivity and changes in capillary forces. In this paper, a detailed study of capillary rock strength behavior after water breakthrough is carried out for four different models. These four models account for particle-particle interactions and include spherical particles in tangential contact, differently sized spheres in tangential contact, squeezed contacts, and detached spheres. The effects of fluid properties (e.g. contact angle and surface tension), rock properties (e.g. particle size, size ratio, contact fabric), and deformation of loaded rock on capillary strength have been mathematically expressed and quantified.

The model calculations indicate: For all the models, capillary strength increases linearly with increasing surface tension between fluid phases.Contact angle influences both the magnitude of capillary strength and its variation with saturation. The larger the contact angle, the lower the magnitude (under the same water saturation) and the faster its decrease with increasing saturation.If the particle size is uniform, small particle size results in high capillary strength. If particles have different sizes, the size ratio of the particles has a similar influence on capillary strength as does fluid contact angle: it affects both the magnitude of capillary strength and its variation with water saturation. However, the relationships are different: the smaller the size difference, the higher the magnitude and the slower its decrease with saturation.For the detached and squeezed models the capillary force (or strength) firstly increases with water saturation, then decreases after a critical saturation, in contrast to the tangential contact model where capillary force always decreases with water saturation.Through the introduction of the strain concept into the capillary models, they can be used to describe capillary strength variations with rock deformation. It is found that capillary strength more-or-less reaches a maximum when spheres are tangentially contacted, and decreases in both the squeezed and detached states, but decreasing much faster with increasing deformation in the squeezed state.

These improvements in the micromechanical modeling of sands will be used to build our understanding of sand production in very weak or unconsolidated rocks, clarifying how sand production is affected by changes in saturation.
Subsidence Prediction and Inversion of Subsidence Data
Authors: Fokker Peter A.
Published: December 2007

This paper presents a forward model for subsidence prediction and an inversion model to calculate the reservoir behaviour from subsidence data. The forward model employs combinations of analytic solutions to the elasticity equations, which approximate the boundary conditions. There are only few free parameters and consequently the calculation times are limited. Still, the model is applicable to a multi-layer subsurface with elasticity parameters changing per layer. The inverse problem is usually ill-conditioned or ill-posed and has therefore been regularized by introducing a priori data about the pressure field or by imposing a certain amount of smoothness. The strength of the regularization parameters are best determined using the model resolution of the inversion and synthetic cases. These also can be used to optimize the experimental design. Inversion of a synthetic case with a "wrong" forward model shows the importance of obtaining reliable subsurface elasticity data. Without such data, the quality of the inversion can be highly compromised.
The Impact of Mud Infiltration on Wellbore Stability in Fractured Rock Masses
Authors: Chen X. , Tan C. P. , Detournay C.
Published: December 2007

Wellbore stability analysis has been included at the well planning stage of many operating companies for its beneficial effect on improvement of drilling efficiency and cost. Such analysis can be very complex and time-consuming due to numerous factors contributing to borehole instability. As such, many wellbore stability analyses take only a few of the factors into account and are mainly based on continuum mechanics. In addition to the detrimental effect of bedding planes and fractures on borehole stability, the rock masses will become more prone to wellbore instability along fractures penetrated by mud due to reduction in the fracture friction angle. However, very few wellbore stability analyses consider the impact of friction angle reduction of fractures when they are infiltrated with mud. Analyses without considering these factors may yield significant errors and misleading predictions.

In this paper, coupled numerical analyses, using UDEC, are presented to investigate the impact of mud infiltration into fractures on wellbore stability under both isotropic and anisotropic stress states. A symmetric regular fracture geometry is considered in the analyses. A simplified, but reasonably realistic, approach is developed to take into account the friction angle reduction of the fractures that occurs when infiltrated with mud. This approach evaluates the extent of mud infiltration and reduces the friction angle of fractures located in the mud-infiltrated region accordingly. The domain of mud infiltration can be either circular or elliptical around the wellbore, which covers both isotropic and general stress conditions.
The Geomechanical Prediction of Fracturing in the Circle Ridge Field, Wind River Basin, WY.
Authors: La Pointe Paul R. , Hermanson Jan
Published: December 2007

Improved recovery of oil from fractured reservoirs often requires understanding how the intensity and orientation of natural fractures vary throughout the reservoir or field. Image logs or core provide excellent fracture data on these fracture parameters in the vicinity of a well, but these often still leave a large portion of the reservoir unknown. Modern 3D land-based seismic can be used to help constrain fracture intensity and directionality in the critical regions between wells, but acquisition and processing may be technically difficult or uneconomic, particularly in older onshore fields where optimized tertiary recovery schemes could increase recovery.

Many important fractured oil reservoirs form in a compressional setting in which there have been various episodes of folding and faulting. The faulting can be quite complex, and involve reverse or thrust faulting, as well as extensional (normal) faulting. Because these folding and faulting events probably represent the peak strain events that the reservoir has experienced, it is likely that the reservoir-scale fracturing developed in response to one or more of these events. Thus, if the strain history could be technically and economically mapped and compared to fracture data from image logs or core, it would be possible to constrain the orientations and intensity of fracturing throughout the reservoir.

This process was carried out at the Circle Ridge Field, in which the fracturing in the Tensleep and Phosphoria Formations controls the efficiency of recovery processes. A 3D palinspastic reconstruction of the strain history for the folding and faulting of this Field was carried out. The strain pattern developed after each stage of deformation was compared to image log and surface fracture data. It was found that the strain produced by the initial folding event predicts fracture orientations and intensity variations quite accurately throughout various structural blocks, and that later faulting events do not seem to have influenced the fracture pattern except in the immediate vicinity of the large faults. This geomechanically-based model of fracturing is being used as the basis for designing tertiary recovery processes for the Field.
Improving Permanent Downhole Gauge (PDG) Data Processing via Wavelet Analysis
Authors: Ouyang Liang-Biao , Kikani Jitendra
Published: December 2007

One of the major issues in processing permanent downhole gauge (PDG) data is that there exist too many transients over a reasonable time period, say six months. A formula has been proposed to predict the transients that may be detected or missed. Reasonable prediction has been achieved via the formula.

Noise usually exists in data recorded by permanent downhole gauges. Denoising is thus one of the most important steps in PDG data processing. In order to denoise the data, data noise level must be estimated beforehand. Unfortunately, the data noise level is typically case-dependent, therefore, it is impossible to identify a universal value for the level that may be used for all the application scenarios.

One appropriate approach to estimate the noise level is to first best fit the data, subtract predicted pressure response from recorded values, and then calculate the noise level based on the difference1. We proposed to apply nonlinear regression via Polytope method2 for best-fitting PDG data to determine the noise level. It is found that the new approach is superior to the least square error (LSE) linear regression as used by Khong1, because the bottomhole wellbore pressure response in a well should be treated as a nonlinear function of time over majority of the well production/injection/shut-in period. Unless very small range of the data (say 2 hours) is considered, linear pressure response with time is not anticipated. Furthermore, with nonlinear regression through the Polytope approach, there is no strong restriction in data quantity and data density, hence, automatic detection of data noise level can be implemented.

Other improvements to the PDG data processing procedure, such as trend analysis, steamlinization of data preprocessing, step outlier removal, and so on, will also be discussed.
Characterization of Reservoir Fluid Dynamics from Multiple Downhole Permanent Sensors
Authors: Manin Y. , Charara M. , Delhomme J. P.
Published: December 2007

In this paper, we first provide guidelines for selecting the most appropriate permanent downhole sensor or combination of sensors for reservoir monitoring, given fluid and rock characteristics. This selection is applied to pressure, electrical, and seismic sensors, based on their respective response equations to formation and rock properties.

We then present two synthetic cases illustrating the interpretation of permanent monitoring data, with emphasis on the benefits of data fusion and data assimilation, referring respectively to the use of multisensor and time-lapse data; more specifically, we show how those approaches enhance the convergence of the inversion process towards the solution.
Using Multilateral Well Technology to Improve Recovery Factor by Water Flooding in a Giant Mature Oil Field in Venezuela Lagunilla Inferior (LL-03)
Authors: Gutiérrez O. , Alter D. , Romero M. , Carreno Z. , León A. , Mohtadi M.
Published: December 2007

The Lagunilla Inferior is located on the eastern part of Lake Maracaibo. It covers an area of around 300 km², with an original oil in place of 6,900 MMSTB and with a total of 1051 wells. The overall recovery factor is around 20% and the current oil field production rate is 30,000 STB/day.

To improve the recovery factor during the 70 years of field production life, four water injection projects in different areas of the reservoir have been implemented. In a recent effort to improve the recovery factor in a selected part of the reservoir with higher residual oil saturation but very low reservoir pressures (300-450 psia), an integrated reservoir study was conducted. In this study the water injection with vertical wells were compared with multilateral well technology by using a numerical simulation model. The water flooding scheme with multilateral wells as injectors and producers shows in this study the highest recovery factor, the best economics indicators and the lowest operational activities compared to the vertical well concepts.

In this paper the results of different pattern concepts and the detailed project planing will be presented. The first phase of the project (drilling of two injection wells and one producing well) will be implemented this year.
Long Distance Decision Making and High Risk Drilling
Authors: Ramp Erich R.
Published: December 2007

Today the Petroleum Industry is moving into more high-risk projects than ever before. A key to the successful completion of many of the projects is the mitigation of project risks and uncertainties. One aspect of risk mitigation is the making of timely and geo-technically correct decisions during drilling operations. The geologically complex nature of many of today’s mega projects often requires numerous experts to be involved in the decision process. If the specific professionals are not available at critical junctures, the results are increased project risk, increased costs, or probably both. A solution is to bring the risk to the experts as/when needed versus taking the experts to the risk.

The Hamaca Project, located in the Eastern-Central portion of Venezuela, is an excellent case example of the benefits of long distance decision making. In Hamaca bringing the drill bit to the experts is the norm not the exception. In just over one year of horizontal drilling operations Petrolera Ameriven drilled approximately 110 horizontal well bores with nearly 564,000 feet of lateral lined section. The lined drain holes had a cumulative 90% net sand contact rate. These results far exceeded original expectations and were in large part due to the long distant decision making.
Upgrading a Heavy Oil Using Variable Frequency Microwave Energy
Authors: Jackson Cindy
Published: December 2007

Heavy oil upgrading experiments were conducted using a variable frequency microwave. While microwave energy itself is readily available as a laboratory technique, microwave ovens that produce frequencies other than 2450 MHz are not. We were able to determine the effect of frequency, by using a variable fre- quency unit at a facility in North Carolina.

Results were promising despite the rapid screening which was employed. Experimental variables included additives, reaction time, and frequency. The addition of activated carbon produced an oil that met pipeline specifications for viscosity and density.

Coke formation determined only on the molybdic acid–iron powder combination; was less than 2 wt.%. This encouraging coke finding may indicate a low coking propensity due to selective heating whereby the bulk of the sample remains at cooler temperatures and reactions are carried out very rapidly.

Overall, the experimental results emphasized that different combinations of material interacted differently at different frequencies. This finding is of utmost importance because the screening of additives has traditionally been focused on 2450 MHz and 915 MHz, which — depending upon the reactants — may not be appropriate for optimum interaction. Frequency was found to have a marked effect upon upgrading.
Waterflooding by Horizontal Injectors and Producers
Authors: Popa Constantin G. , Turta Alex T.
Published: December 2007

Using horizontal wells in a waterflooding process, a higher sweep efficiency for less cost is expected as opposed to the use of classical patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate such a process. The paper presents an analysis of how the overall efficiency of a waterflooding process is influenced by the well pattern using horizontal injectors and producers in different configurations.

Recent investigations used vertical injectors and horizontal producers, with the horizontal well completed at the top of formation and having its toe close to the injection well, which was perforated at the lower part of formation. This process, known as a short-distance Toe-To-Heel Waterflooding "(TTHW) process", was found sound for the light-heavy oils with viscosity up to 2,000 cP, and proved to have maximum efficiency for relatively thick formations.

The general necessity to inject higher water rates, simultaneously with the preservation of a certain control on the injection, prompted the investigation of the use of horizontal wells as injectors both for light-heavy oil and light oil recovery in thin oil reservoirs in a long distance displacement configuration, as well.

A two phase two dimensional numerical simulator for thin formations to investigate the Waterflooding by Horizontal Injectors and Producers, including an "areal" TTHW process, was used. Both the sink/source and the discretized well were considered, in order to estimate the effect of pressure drop along both injectors and producers on the oil recovery performance. The results showed that the pressure loss along the horizontal section has a significant influence on the sweep efficiency.

A numerical simulation study for 10 oils having viscosities between 1 cP and 150 cP was undertaken. The study was performed for both long-distance and short-distance displacement configurations, although for some oil viscosity values it was made just for illustrative purposes. The main parameters, such as time of water break-through, oil recovery at break-through, sweep efficiency, injection-production pressure drop, etc were analyzed in all cases.

For optimization purposes two types of configuration were investigated: a staggered parallel horizontal wells configuration, having their heels in opposite directions and their toes arranged in a direct line, and an L shaped configuration, with perpendicular horizontal wells having their toes relatively close to each other.
Challenges Faced in Well Construction as Heavy Oil Exploitation Goes Deeper
Authors: Davy Claire
Published: December 2007

This paper introduces the Mukhaizna Heavy Oil Project, one of PDO’s (Petroleum Development Oman) "T50" projects that expects to increase recovery of these Middle East reserves to a 50% Target.

Well construction faces several extra challenges for this, the world’s deepest reservoir yet to be thermally exploited. Loss zones and cementation hurdles require innovative solutions, even for vertical wells.

The methods by which the field is to be exploited by predominantly vertical wells are outlined. The limitations faced in designing these wells are set out. The corresponding subjects of further technology development are catalogued.

Delivery of this paper encourages an environment for reception of feedback from both experts and suppliers to assist in planning a path to obtaining solutions and putting these into practice.
Optimization of Smart Well Control
Authors: Yeten Burak , Durlofsky Louis J. , Aziz Khalid
Published: December 2007

Downhole inflow control devices allow for the flexible operation of nonconventional wells. They provide the ability to independently control each branch of a multilateral well and can therefore be used to maximize oil production or to minimize the production of unwanted water or gas. In this paper, a method for the optimization of the operation of smart wells; i.e., wells containing downhole sensors and inflow control devices, is presented and applied. The method entails the use of a conjugate gradient optimization technique applied in conjunction with a commercial reservoir simulator that contains a detailed multisegment well model. The overall optimization technique is applied to several example problems involving different types of wells and geological models as well as multiple geostatistical realizations. The improvement in predicted performance using inflow control devices, which is as high as 65% in one case, is demonstrated for all of the examples considered. There is, however, significant variation in the level of improvement attainable using these devices, so sophisticated decision-making techniques may be required when considering their use in practice.
New Method For Predicting Deliverability From Variable-Rate Drawdown Data
Authors: Pascal H. , Quillian R.G.
Published: December 2007

In this investigation, a new method was developed for analysis of variable-rate drawdown tests of low-permeability gas reservoirs. Rate variation, usually declining during the test, is considered as a continuous function of time, contrasted with most other multiple-rate solutions which superpose the effects of representative rates corresponding to discrete time steps.

A computer program was developed to perform a non-linear least squares determination of the coefficients in the equation which uniquely describes the rate-time profile recorded during the test. A mathematical model was formulated in terms of the Volterra linear integral equation. The unique pressure response as a function of time, corresponding to what the authors' term a constant rate, may be determined from this model. A companion computer program was written to provide a numerical solution of the model, including values for effective gas permeability and skin. After obtaining from the model appropriate pressure response f(tk) as a function of time, conventional (semilog) analytical procedures may be used.

Several field cases are presented which illustrate the good match achieved between predicted pressure history and that recorded at wells pressure history and that recorded at wells producing from a low-permeability gas reservoir. producing from a low-permeability gas reservoir. In the case of an unfractured reservoir, a good history match was achieved without further assessment of permeability and skin data. Wells subjected to hydraulic stimulation exhibited the enfluence of the vertical fracture system during the drawdown test resulting in optimistic values for permeability and skin. In such cases, a good history match was achieved by correcting permeability using the methods proposed by Russell and Truitt.

Introduction

Methods for analyzing flowing well behavior to obtain estimates of the physical parameters of the reservoir require as a fundamental condition that flow rate be held constant. This is an unreasonable requirement applied to low-permeability gas reservoirs where rates often vary (decline) uncontrollably during a single-point drawdown test. Several descriptions appear in the literature for conducting and analyzing variable-rate tests, usually entailing application of the principle of superposition in time.

P. 207
Relative Permeabilities And Capillary Pressure In The Burgan And Wara Sands
Authors: Hetherington George
Published: December 2007

1961 Middle East Regional Meeting; Dhahran, March 27–29, 1961

Gas-oil relative permeabilities of the Burgan and Wara sands can be roughly correlated with absolute permeability. Gas relative permeabilities are related to oil relative permeabilities and to capillary pressure by the Kozeny-Carman equation only if the tortuosity coefficient is considered a function of saturation and different for each absolute permeability. It must be determined empirically.

A regular relation was observed between initial water saturation and the amount of oil which can be displaced by water. This seems to be the same for Uncleaned cores taken with oil-based mud and for extracted cores. It therefore seems reasonable to assume that it also applies to the sand in situ in the reservoir. If it does, the oil recoverable by water drive can be estimated from the initial interstitial water saturation.

Initial water saturation of the Burgan and Wara sands decreases as absolute permeability increases. The residual oil saturation after water flooding also decreases with increasing absolute permeability. From this and other evidence, it appears that these sands are partially oil and partially water-wet. At low water saturations they exhibit the behaviour of water-wet sands but at higher water saturations they behave as though they were oil wet.
Lubricant SSP - The Proven Lubricant To Reduce High Downhole Torque
Authors: Tyldsley D.
Published: December 2007

Introduction

Most offshore drilling operators have experienced unique physical drilling problems whilst operating in the coastal waters of the British Isles and North Sea areas. The magnitude and effect of each problem is often novel, requiring specific corrective action. Improved physical techniques and chemical treatment are physical techniques and chemical treatment are continually being sought to provide an interim or permanent solution. This paper traces the development and application of a drilling lubricant which has been extensively utilised to overcome the problems of downhole torque and drag encountered in drilling deviated wells. The lubricant, which is based on a vegetable oil derivative, is added to a water based drilling fluid system to provide a significant reduction in torque and friction without creating secondary well problems. A technique which presents several associated problems is drilling directional wells. Directional drilling has problems is drilling directional wells. Directional drilling has been universally applied, and holes with deviated sections greater than 70 degrees have been successfully, completed. This beneficial drilling technique has introduced several undesirable features requiring corrective action, i.e.:downhole torque:drag: . stuck-pipe:

Downhole torque is usually produced by a combination of the drill pipe rotating on the side of the hole. (either open or cased sections) the angle of deviation, the friction at the bit and the general requirement for extra stabilisers and 'dog- legging' of holes after correction runs. In deviated drilling all of these effects cause greater contact of drill stem to hole, and hence greater torque and increased probability of resultant stuck pipe. The standard solution for most of these problems is to incorporate diesel oil or lubricity additives into the drilling, fluid. Diesel oil often does not provide a satisfactory solution to these drilling problems.
Gas Lift Increases High Volume Production From Claymore Field
Authors: DeMoss E.E. , Tiemann W.D.
Published: December 2007

Introduction

The present production operations on the Claymore A platform are the results of the cooperation of reservoir and platform are the results of the cooperation of reservoir and production personnel. Early in the development of production personnel. Early in the development of Claymore field, reservoir simulations were run to estimate the productivity indexes of the wells and to determine reserve productivity indexes of the wells and to determine reserve estimates. This work exposed the need for a pressure maintenance programme. So, during the first year. water injection into the reservoir was initiated. This was done early to eliminate (or substantially reduce) a big drop in the static reservoir pressure. Without water injection, a 20 per cent drop in static reservoir pressure was expected per cent drop in static reservoir pressure was expected during the first year, and with productivity indexes ranging from 5 to 36 bpd/psi, it was essential that an artificial lift system be selected and implemented into the completion plans as soon as possible. plans as soon as possible. Since the formation GOR of the Claymore was low, gas lift could substantially reduce the flowing bottom hole pressure and increase the Field's production rate. Even pressure and increase the Field's production rate. Even though the formation GOR was low, it was enough to supply fuel for the platform and circulated gas for lifting the wells. The gas for platform fuel needs is taken from the low pressure manifold. As make-up gas was needed for any reason, a gas line from the Piper Field was made available to furnish gas to the compressor suction gas header. At first the Piper was used only at special times. But the need for Piper gas increased each month and a daily requirement was established. In May 1978, the average daily use of Piper gas to the Claymore was about 4,200 mcf/d. The availability of Piper gas, therefore, played an important role in the selection of gas lift to played an important role in the selection of gas lift to produce the Claymore. produce the Claymore. A detailed study of the capability, of gas lift produced the conclusions and design conditions in Table 1. As seen on Table 1. 1,850 psi is the gas lift surface injection pressure at the well. Studied but not selected was 1,600 psi pressure at the well. Studied but not selected was 1,600 psi surface gas pressure.
The Biological Implications For The Filtration Of North Sea Injection Water
Authors: Finch Edward M.
Published: December 2007

As a result of core injectivity tests and alternative filtration trials carried out on Forties platforms it became apparent that certain components of the North Sea biomass have a direct bearing upon the ultimate quality of North Sea injection water. This view is substantiated by the continuous monitoring of the fine filters currently in use in the Forties Water Injection System. This paper discusses those species which according to test data and observations of the fine filters are considered most likely to influence water quality. Their seasonal frequency and lateral and vertical distribution in the North Sea are also commented upon. The conclusion is drawn that filtration of North Sea Water is necessary prior to well injection

Introduction

Sea Water injection of the Forties oilfield commenced in December 1976 and is currently going ahead at a rate of approximately 125,000 b/d for each of the four platforms. The details of the Forties water injection system have been published and will not be mentioned here in any detail. published and will not be mentioned here in any detail. Suffice to say that the sea water is won from a depth of 200 ft below sea level and is filtered before being pumped down to the aquifer at a well-head pressure of 1,200 psi. An initial coarse filtration of the water is obtained by a 80 um stainless steel screen. Fine filtration down to 5 um is achieved by backwashable. Plenty cartridge filters containing replaceable fibre elements which are positioned upstream of the main injection pumps. The decision to filter the sea water prior to injection was based upon information gained from numerous on-site tests which in turn were followed by filtration trials to ensure the selection of the most efficient fine filter element available for use in the Forties environment. The current paper which is a sequel to one published in 1978 is limited to a discussion of the organic content of the injection water and its relationship to the fine filters.
Determining Average Reservoir Pressure From A Pressure Buildup Test
Authors: Taylor Timothy D. , Caudle Ben H.
Published: December 2007

Results presented in this paper show that significant errors can be obtained by approximating an actual drainage area by a simple geometric shape when determining average reservoir pressure by methods presently available. This paper presents a method for determining true average reservoir pressure from a single well buildup test in a multi-well reservoir of any shape without prior knowledge of drainage area shapes. The method requires one computer run of modest cost to be used with the conventional pressure buildup test on the well.

Introduction

A knowledge of average reservoir pressure, p, is important in characterizing a petroleum reservoir. It is fundamental in computing oil in place or water influx from material balance, determining the pressure distribution for the detection of fluid movement and in predicting future reservoir performance in primary, secondary, and tertiary recovery projects. The purpose of this paper is to present a method for obtaining true average reservoir pressure from a single well pressure buildup test in a multiwell, multi-rate bounded petroleum reservoir producing under unsteady state conditions.

The most commonly used methods for obtaining average reservoir pressure from buildup tests require an estimation of the shape of the drainage area of the well being tested. This shape must then be approximated by one of several regular geometric figures for which solutions of the pressure function are available by the method of images1. Figure 1 shows the pressure function solutions (type curves) for various well locations within some regular drainage areas. A more complete set of these solutions for other regular shapes can be found in the Matthews, Brons, and Hazebroek1 paper and books by Matthews and Russell2 and Earlougher3.

Having selected the most closely resembling available shape, average reservoir pressure is then determined by entering the plot at the dimensionless time of the buildup test, as shown in equation (1), obtaining a value for dimensionless pressure, pD, and calculating p from equation (2).Equations 1 and 2

The pressure extrapolated to infinite shut-in time, p*, and the slope of the straight line portion of the buildup curve, m, are available from the customary plot of shut-in well pressure versus log.

Discussion

Recent developments4 permit bounding of the continuous line source solutions for unsteady state flow in any drainage shape. A computer model has been formulated which can describe the pressure behavior in any shape reservoir containing any number of wells. The model can check the Matthews, Brons, and Hazebroek1 type curves for regular shapes and extend their findings to drainage shapes not capable of being created by image wells.
Forty Years of Steam Injection in California – The Evolution of Heat Management
Authors: Hanzlik E. J. , Mims D. S.
Published: December 2007

Steam injection EOR began in California forty years ago, and has been highly successful. As a consequence, California's thermal recovery operations represent a leading source of EOR production in the world.

The understanding of most early thermal recovery operators was limited to the concept of "heat reduces heavy oil viscosity, and reduced viscosity means more production." Steam injection was attempted in almost any reservoir having viscous oil with little appreciation of other recovery process considerations. Although several early pilot projects were steamfloods, most early applications were cyclic stimulation. During the late 1970's, steamflooding became predominant, and many people considered steamflooding to be a displacement process (hence the term "steam drive’). With this paradigm and high oil prices, there was little impetus to understand efficient use of heat. The predominant philosophy was "If you want more oil, inject more steam." With the later collapse of oil prices, operators returned to review process fundamentals and to determine how to more efficiently operate steam projects. This paper discusses the shift to an override, or gravity drainage, model concept. This helped lead to reduced steam injection and improved thermal efficiency through the use of heat management. This paper discusses the shift to the concept of steam override and gravity drainage as steamflood recovery mechanisms and the subsequent use of heat management practices that improved thermal recovery efficiency.