bluuebunny/crossref_metadata_2025 huggingface dataset:
Huge Change in Deep Reservoirs Development Strategy using High Angle Wells. El Furrial Field. Venezuela.
Authors: Gil R Jose A. , Colombine Willie , Rodriguez Pavel
Published: December 2007

El Furrial field is located 18 miles west from Maturin city, in eastern Venezuela (Fig. 1). It was discovered in June 1986 by FUL-1 well which produced initially 7000 barrel/day 28°API oil. The El Furrial structure is a giant faulted anticline oriented NE-SW. The depositional sands of Cretaceous to Oligocene age which are 1500 feet thick were encountered below 12500 feet. The Naricual formation is the main reservoir in El Furrial field.

The STOOIP is 6880 MMBls. The reservoir has a porosity of 13 % and its permeability ranges from 100 md to 1300 md. The reservoir pressure declined rapidly during initial development. The lack of natural pressure support was due to the sealing by a Tarmat Layer underneath the Naricual formation. A pressure maintenance project using peripheral water injection was initiated in 1992 in order to keep the pressure above the asphaltene flocculation point, which is about 6500 psi. It would also increase the recovery factor from 13% under natural depletion to 27% under water injection. Crestal Miscible Gas injection started in August 1998 with the aim to further increase the oil recovery. Currently some 550 MBWD water and 300 MMCFD gas are being injected. Drilling and completion strategies have changed with time from vertical wells with dual completions to (highly) deviated wells completed with a single production string.

The new development strategy focused on drilling high angle wells as a way to maximize the oil recovery at reduced cost. An evaluation had shown that high angle wells could be capable of producing up to 20000 BOPD. These wells would delay water and gas breakthrough, increase cumulative reserves per well, reduce operating costs, avoid local pressure sinks and have a positive environmental impact. Four high angle wells have been drilled in the Naricual Formation up to now. The operational problems have been well studied and the learning curve has resulted in further optimization.

This paper describes the well planning, the optimum well design, the results and the experience gained in the drilling of four deep high angle wells in El Furrial field.
Laboratory Observations of Gravel Placement Techniques
Authors: Novonty Rudolf J. , Matson Ronald P.
Published: December 2007

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

In order to better understand past problems and experiences in field applications of problems and experiences in field applications of gravel-packing treatments, a field-size acrylic well model was constructed. This model was used to examine visually the placement of gravel outside the perforations and inside the annulus between the liner and casing. The results and observations were correlated with previous field experience in Louisiana and previous field experience in Louisiana and California. These studies can be broken down into five major areas of interest.The effect of slurry density and viscosity on fluid displacement.Pad design.Sand transport through perforation tunnels.Sand dehydration and node formation.Rathole design.

Different treatment parameters were studied, including the effects of viscosity, sand concentration, method of application, hole condition, and deviation. Both low-viscosity fluids carrying low concentrations of gravel and high-viscosity fluids carrying high concentrations of gravel were evaluated. As a result of the observations presented in this paper, the engineer can gather new insights on paper, the engineer can gather new insights on treatment performance and pack stability. Therefore, these studies should lead to better future job designs and application techniques.

Introduction

The principles of gravel packing are based on the theory of sand bridging to create a highly permeable filter of gravel between the sand producing formation and production equipment. Gravel-placement techniques have evolved through the years from simply dumping gravel down the wellbore to pumping gravel through very sophisticated tools, port collars, and combination packers. Prior to the late 1960's, the fluids used for gravel placement were salt water, low-viscosity crudes, and muds. The use of low-viscosity fluids meant the placement of gravel had to be accomplished placement of gravel had to be accomplished using high pump rates (3 to 6 bbl/min) and low gravel concentrations (1/4 to 1/2 lb/gal). This combination was necessary to prevent the gravel from bridging in tubing or in gravel-packing tools. To improve the success and productivity of a gravel pack during this period, emphasis was placed on improved completion techniques, i.e., filtered fluids, perforating, and gravel sizing.
Alum-Non Ionic Surfactant Combination: an Effective Demulsifier
Authors: Bhattacharya S.N. , Ramana P.V. , Singh Kulwant
Published: December 2007

Introduction

Oil field emulsions are a problem all over the world. It is well established that the stability of these emulsions depends upon the properties of the crude oil and water and production techniques employed. production techniques employed. The common methods in vague in petroleum industry for demulsification are thermal, chemical and electrical on their combinations. Though the literature on this subject refers to the use of inorganic salts like lime, calcium chloride, ferrous sulfate, etc., Kalichevsky and Kobe have indicated the futility of these compounds for demulsifications.

The present practice, however, is to use high molecular weight organic surface active agents of ionic or non-ionic nature for this purpose in conjunction with thermal and electrical methods. Stassner has reported the pH control as an effective aid in the process of demulsification.

Most of the emulsions usually respond to one of these methods or their combination. While working with one of the emulsions of North Gujarat (India) fields, it is observed that none of the above methods has been effective.
A Two-Phase Coning Model Using Alternating Direction Galerkin Procedure
Authors: Kebaili A.L. , Thomas G.W.
Published: December 2007

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

THIS PAPER IS SUBJECT TO CORRECTION

This study presents a development of an Alternating Direction Galerkin (ADG) method following some theoretical work of Douglas and Dupont. The technique is applied to the construction of a two-phase coning simulator in cylindrical coordinates. Solutions are approximated in smooth bicubic Hermite subspaces. The non-linear coefficients in the differential equations are interpolated into a Hermite subspace with a mesh three times finer than the solution mesh. This interpolation scheme provides an order of accuracy consistent with and as high as that of the method of solution. Also it makes a substantial reduction in computer time. A novel method has been devised to simplify the notation and programming effort compared to work previous done in this area. In addition, a permutation matrix is employed to bring the matrix problem for each sweep into a simpler consistent form such that a block solution technique can be readily applied.

Finally, some computational results for hypothetical coning problems are presented and discussed. These are compared to those problems are presented and discussed. These are compared to those obtained from a non-alternating Galerkin formulation and comparable finite difference model.

Introduction

For the past two decades reservoir engineers have been confronted with the problem of describing and predicting reservoir behavior. The lack of analytical solutions to the partial differential equations generated by such problems, along with recent advances in high speed electronic computers, has led to numerical methods using finite difference techniques. Despite the relative success of these methods, it was soon discovered that not all problems are adequately amenable to such treatment. Certain reservoir phenomena involving sudden changes in the dependent variables are poorly simulated by finite difference techniques. For example, to describe the zone of rapid change occurring in Buckley-Leverett type displacement, one must resort to excessive grid refinement. Computation of pressure and saturation distributions around wellbores must be approached in the same manner. The main drawback is that only discrete solutions in time and space are obtained by finite difference methods. Furthermore, these techniques are frequently limited by stability and convergence considerations.

Because of these problems attention has shifted to numerical methods which do not require spatial discretization of derivatives. Galerkin's method is one of these. Combined with piecewise polynomial approximations, Galerkin's process yields results polynomial approximations, Galerkin's process yields results superior, to those obtained by the finite difference technique.
Numerical Solution of Slightly Compressible Single Phase Transient Flow Problems by Spline Functions
Authors: Dogru A.H. , Alexander W.C. , Panton R.L.
Published: December 2007

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

Two dimensional spline functions were utilized in the solution of the linear diffusion equation both with and without a sink within the domain. A collocation method of solution was used and several types of spline representations were investigated. Results were compared with finite difference solutions and with the analytical solutions. B-splines with an extended region of definition were concluded to be superior. For problems with a sink the B-splines alone were not accurate, however, supplementing the splines with a log term produced very good results.

Introduction

In engineering design, ship builders and others often use a spline, an elastic ruler which can be bent so that it passes through a given set of points. Under certain assumptions the curve can be approximately described as being built up of different third degree polynomials (cubic polynomials) in such a way polynomials (cubic polynomials) in such a way that the function and its first two derivatives are everywhere continuous. The third derivative however, can have discontinuities at the given points. Such a function is called cubic spline.

In recent years, spline functions have found wide applications in approximation theory, data fitting, interpolation and so on 4, 9, 15, 16, 17. A smaller amount of work has been devoted to the solution of ordinary and partial differential equations. partial differential equations. Application of spline functions in reservoir problems was initiated by Culham and Varga. problems was initiated by Culham and Varga. These authors used spline functions to approximate the space derivative in a one dimensional nonlinear parabolic partial differential equation which describes the real gas flow in a porous media. The time derivative, however, was approximated by means of various finite difference schemes. They employed Galarkin's and some non-Galarkin type methods to obtain the solutions. Cubic spline basis functions were recommended as the optimum choice for a single-phase flow.

When a spline function is used to approximate the solution of a differential equation, two different methods may be used to eliminate the space dependency. These are namely, Galarkin's method (or Integral Methods) and collocation method. Comparisons of these two different solution methods were made by Panton and Salle on a one dimensional heat Panton and Salle on a one dimensional heat conduction equation. They reported that integral methods give higher accuracy in the solution but programming is quite laborous.
Numerical Simulation of Temperature Profiles and Oil Production During Dry or Wet In -Situ Combustion for an Inverted 5-Spot Pattern
Authors: Chien Sze-Foo , Shum Yick-Mow , Korstad Ralph J.
Published: December 2007

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

A numerical simulation is developed to determine the temperature profiles and oil production for an inverted 5-spot pattern subjected to dry or wet in situ combustion. The basic equations required for the simulation are derived and discussed. The simulation takes into consideration the heat of combustion, the reservoir heat capacity, the conduction and convection of heat through the reservoir, and the conduction of heat between the reservoir and the cap and base rocks. Oil production is calculated through the use of the temperature-oil saturation relationships, a production delay factor and a well-capturing factor.

Examples of temperature profiles and oil production for the dry and wet combustion processes are presented. The features of the temperature profiles produced from the simulation appear to produced from the simulation appear to be in agreement with those reported by others in the literature. For the same injection rate of steam or water simultaneously with air there is not much difference in the temperature profiles ahead of the combustion front. However, behind the front there is definitely a better utilization of heat (i.e., heat scavenging effect) in the case of water injection.

Introduction

In situ combustion is one of the promising techniques for the recovery of promising techniques for the recovery of heavy oil. With this process, air is injected into the formation to burn a part of the oil in-place. Heat part of the oil in-place. Heat generated by combustion is used to heat up the formation and its contents. The increase in temperature reduces the oil viscosity and thus increases its mobility. Ahead of the combustion front, the formation water is vaporized and together with water generated by combustion produces a steam zone. Further ahead, this steam condenses and produces a hot condensate zone. Hence, the in situ combustion process includes both steam and water flooding mechanisms.

Many processes for in situ combustion have been studied and reported in the literature. Among these are forward combustion, reverse combustions and wet combustion.
Land Subsidence as a Result of Natural Gas Extraction in the Province of Groningen
Authors: Schoonbeek J.B.
Published: December 2007

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

This paper was prepared for the SPE-European Spring Meeting 1976 of the Society of Petroleum Engineers of AIME, held in Amsterdam, The Netherlands, April 8–9, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made.

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

When the size of the Groningen gas field was recognised, it was realised that substantial subsidence might occur at the surface. Intensive studies were initiated to predict future subsidence and measuring systems were developed. In 1971 N(ederlandse) A(ardolie) M(aatschappij) published subsidence prognoses up to the final production stage of the field, where a maximum subsidence of approximately 1 m was predicted. From the various measurements in and over the field it has been proved that subsidence indeed takes place, however, at a degree which is considerably less than predicted.

After refinement of the original mathematical model and incorporating the latest field information, such as updated geological interpretation and the pressure distribution in the reservoir rock, the calculated spatial distribution of subsidence has proved to correspond well with that obtained from actual levelling surveys.

Based on subsidence/pressure behaviour in time and on geological considerations it is concluded that the compaction measurements in the laboratory are not representative for the reservoir in-situ.

An excellent history match could be obtained for the subsidence behaviour so far. Prognoses based on this history match now Prognoses based on this history match now result in a figure of 30 cm for the final maximum subsidence.

Introduction

The Groningen gas field in the Netherlands was discovered in 1959, but its large size was not recognised until 1963. The field is now known to extend over an area of approximately 900 km2. The sandstone reservoir belongs to the Permian Rotliegend formation. Its depth of burial is approximately 2900 m. The gross thickness increases from 70 m in the south to 240 m at the northern boundary. The in-situ weighted average well porosity ranges from 16 to 20 percent, the permeability from 0, 1 mD to percent, the permeability from 0, 1 mD to a few Darcies.
Fluidization in Pipeline Burial
Authors: Boom J.
Published: December 2007

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

This paper was prepared for the SPE-European Spring Meeting 1976 of the Society of Petroleum Engineers of AIME, held in Amsterdam, The Netherlands, April 8–9, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made.

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

Content;AbstractIntroductionFluidisationExperiencesDevelopmentsConclusion

1. Abstract.

In recent years the application of high-pressure jets, sometimes used in conjunction with suction-dredging, has been developed into a useful tool for underwater trenching for pipeline burial. In soils with little or no cohesion the trench will be apt to fall in after passage of the apparatus. This prevents the pipe from reaching the desired depth, even after several runs over the pipeline. To overcome this difficulty, Shell have investigated the use of fluidisation in their Rijswijk laboratory. Hanab, a company of the Stevin Group, made the first experimental application of the principle in 1971. Since then approx. 60 km pipeline, ranging from 4" to 36", has been buried. The cover reached in one single run varies from 1 m to 4,5 m. The paper described the experience gained so far with this new method.

2. Introduction

In recent years equipment is being designed and built for the burial of pipelines lying under water. In general, pipelines lying under water. In general, these machines constist of a U-shaped frame hanging over the pipeline provided with mechanical means or high pressure water jets to cut the soil next to and under the pipeline.
Estimation of Gas in Place Using Optimal Control Theory
Authors: Sinha Mihir K.
Published: December 2007

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

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

This paper presents a procedure for estimating the gas in place for volumetric gas reservoir using the Material Balance Principle and Optimal Control theory. Principle and Optimal Control theory. The reservoir model includes connate water expansion, rock compaction, shale water influx and limited water influx from a bounded aquifer of limited extent. Hydrocarbon phase behavior includes gas compressibility factors.

Validity and predictability of the model have been tested using two published test problems. These problems are:the NS2B Reservoir of the North Ossum Field, Louisiana, andthe Anderson "L" Reservoir in South Texas.

The method was then used to determine the reserve of a large gas reservoir in Wyoming. The results obtained from the Wyoming field have been compared with the results obtained using other methods. The results obtained by different methods agree reasonably well.

Introduction

A reliable estimate of gas in place, recoverable reserve, most probable future life and future production rates, all play very important roles in the Natural Gas Industry. These values are needed for efficient planning of long range contracts and future commitments, scheduling compressor installation, well drilling and other investment decisions. Investment decisions are generally based on profit maximization over the life of the field. Hence, the need for reliable information for management decision can never be over emphasized.

Estimation of gas in place or recoverable gas is one of the most important aspects of gas reservoir analysis. Principle methods of predicting gas in place are:Volumetric MethodProduction Decline Method(Rate-Time, Rate-Cum plots)Material Balance Method(P/Z vs Cum. Prod. plot)
Foam Cementing Applications on a Deepwater Subsalt Well—Case History
Authors: Moore S. , Miller M. , Faul R. , D'Agostino J.
Published: December 2007

The Boris prospect is a deepwater well drilled at Mississippi Canyon. This exploratory well was drilled in a subsalt environment, which provided many zonal-isolation challenges. Deepwater wells in this area can have shallow water flows (SWF),1 long sections of salt, and disturbed zones or rubble zones above and below the salt section. While all these hazards were not encountered during the drilling of this well, foamed cement was an integral part of the plan to deal with them. The paper is a case study of how a new foamed-cementing process was used to solve the challenges associated with the zonal isolation and to help Shell meet the target for the number of drilling days. The paper will cover the cementing process used on three primary casing strings during well construction.
Thermally Induced Wettability Alteration to Improve Oil Recovery in Fractured Reservoirs
Authors: Al-Hadhrami Hamed S. , Blunt Martin J.
Published: December 2007

Many naturally fractured reservoirs are oil-wet and during water injection water will not imbibe into the matrix but will preferentially flow through the fractures resulting in very low oil recoveries. For instance, the Ghaba North field in Oman is an extensively fractured oil-wet carbonate which that has only achieved 2% recovery after over 20 years of production.

Experiments on core from fields in Oman and elsewhere have indicated that the rock will undergo a transition from oil-wet to water-wet as the temperature is increased. The temperature could be increased in a reservoir setting through steam or hot water injection. The wettability change is due to desorption of asphaltenes from the rock surface.

It is proposed to inject steam or hot water to heat the matrix sufficiently to induce a wettability change, rendering it water-wet. Hot water in the fractures can spontaneously imbibe into the matrix displacing oil and resulting in favorable oil recoveries.

A one-dimensional model of the saturation and temperature profiles during imbibition into a matrix block is developed and solved analytically. Example solutions and typical time scales for recovery are proposed. Using Ghaba North properties the imbibition rate is limited by thermal diffusion through the oil. The advancing water front is located where the rock temperature equals the transition temperature for wettability change. It is estimated that around 30% oil recovery could be achieved in single matrix block after approximately 700 days. In less permeable media, the imbibition rate is limited by capillary forces, and the temperature front would move ahead of the water, resulting in slower recovery.
Gel Propagation Through Fractures
Authors: Seright R. S.
Published: December 2007

When gels are used for conformance control in reservoirs, a need exists to determine how much gel should be injected in a given application and where that gel is distributed (i.e., placed) in a naturally fractured reservoir. These parameters depend critically on the properties of gels in fractures. This paper describes an investigation of how Cr(III)-acetate-HPAM gels propagate and dehydrate (i.e., lose water through leakoff) during extrusion through fractures. These studies included fractures with lengths from 0.5 to 4 ft, and heights from 1.5 in. to 12 in., and gel injection fluxes from 129 to 33,100 ft/d.

Based on the experimental results, a model was developed to quantify gel propagation and dehydration during extrusion through fractures. The model indicated that to maximize gel penetration along fractures in field applications, the highest practical injection rate should be used.

Additional tests indicated that significant advantages could be realized for gels made using polymer with the highest available molecular weight. In addition to being potentially more cost-effective, these gels may penetrate deeper into a fracture system than gels made with lower molecular weight polymers.
Increased Oil Production From Bachaquero-01 by Steamflooding Using Horizontal Wells
Authors: Rodriguez M. G. , Mamora D. D.
Published: December 2007

Three-dimensional thermal compositional simulation studies were conducted to evaluate the performance of three horizontal wells under cyclic steam injection and steamflooding in the Bachaquero-01 heavy oil reservoir, Venezuela. In the steamflooding scheme investigated, the horizontal wells were used as injectors with existing (and new) vertical wells as producers. Simulation results indicate: (i) oil recovery of about 15% of original-oil-in-place with cyclic steam injection compared to about 25% under steamflooding with no new producer, and about 50% under steamflooding with additional producers, (ii) main benefits of steamflooding are in re-pressurization and improved thermal efficiency, and (iii) higher oil recovery with additional wells result from improved areal sweep efficiency.
Regional Upscaling: A New Method to Upscale Waterflooding in Heterogeneous Reservoirs for A Range of Capillary and Gravity Effects
Authors: Coll C. , Muggeridge A. H. , Jing X. D.
Published: December 2007

Waterflood sweep efficiency is a function of the prevailing flow regime and the reservoir heterogeneity. However small scale heterogeneities cannot be represented explicitly in field scale simulation models because of limitations in computer speed and memory. Hence pseudo relative permeabilities are used to represent the average effects of small scale heterogeneity on the large scale flow. However many different methods for developing pseudo relative permeabilities are reported in the literature. The best pseudoisation method to use for a particular problem will depend upon the flow regime. For example, vertical equilibrium will apply for gravity or capillary gravity dominated displacements, steady state pseudos can be used for capillary dominated flows whereas dynamic methods can be used for viscous dominated flows. In homogeneous reservoirs the dominant flow regime can be determined from examination of the relevant scaling groups. In heterogeneous reservoirs the flow regime can vary with permeability so different flow regimes may prevail in different parts of the reservoir. Hence different upscaling methods may be needed in different parts of the reservoir. This paper presents the results of the application of a new upscaling methodology called ‘Regional’ upscaling. The method uses dimensionless numbers calculated on a grid block by grid block basis (referred to as ‘Local’ dimensionless numbers) to determine the dominant flow regime in each fine grid cell. The coarse grid is selected based upon the spatial locations of the different force regimes operating in the fine grid simulation model and the pseudoisation method varies across the grid. The method is compared with different pseudoisation methods and its accuracy examined for breakthrough time and recovery prediction for a reservoir in Lake Maracaibo.
Evaluation of Minimum Miscibility Pressure and Composition for Terra Nova Offshore Project Using the New Vanishing Interfacial Tension Technique
Authors: Rao D. N. , Lee J. I.
Published: December 2007

Terra Nova oil pool is the second largest oil pool discovered in the Grand Banks of the Canadian East Coast and is under development with production startup target date in late 2000. As a part of the oil recovery process selection criteria, miscibility conditions were determined for Terra Nova oil with various enrichment levels of gas available from the offshore production facilities, using the newly developed Vanishing Interfacial Tension (VIT) technique.

The VIT technique is based on the concept that the interfacial tension between the gas and crude oil phases at reservoir temperature must reduce to zero as these two phases approach the point of miscibility. The concept of zero-interfacial tension at miscibility is, in turn, based on the well-accepted fact that the interface between the phases must vanish, as they become miscible with one another. Thus, the minimum miscibility pressure (MMP) and minimum miscibility composition (MMC) can be determined precisely by measuring gas-oil interfacial tension as a function of pressure and gas composition, down to as low an interfacial tension as the measurement technique allows, and then extrapolating the data to zero interfacial tension.

This paper presents the details of this new VIT technique and its evaluation against slim-tube tests, and discusses its application to the Terra Nova gas injection scheme. The interfacial tension data obtained at reservoir conditions using the computerized axi-symmetric drop shape analysis technique are presented as a function of pressure, gas composition, and the mode of gas-oil contact (first contact or equilibrium). In addition to providing visual evidence of miscibility as the point of zero interfacial tension is approached, the VIT technique is rapid in that it enables the experimental determination of MMP and MMC within about 2-3 days as against 4-6 weeks required by the slim-tube technique.
Use of the 4-Component Todd and Longstaff Method as an Upscaling Technique in Simulating Gas Injection Projects
Authors: Fayers F. J. , Haajizadeh M. , Lin C. Y. , Taggart J.
Published: December 2007

Gas injection is becoming a significant and economic IOR method, often implemented as a miscible or "near miscible" WAG project. Numerical dispersion effects in standard compositional simulation of WAG processes can cause serious errors in the predicted phase behavior, so that the compositional results for large area models can be very misleading.

The 4-component Todd and Longstaff (T&L) method provides the basis of an upscaling technique, since it approximately represents the physics of these near-miscible processes, and includes five adjustable parameters to facilitate coarse grid T&L matching. The solutions of the T&L equations are well behaved, including less serious sensitivity to numerical dispersion. The upscaling is achieved systematically from a combination of steps with a final stage based on fine grid compositional reference solutions for small representative elements of the reservoir. Details in reservoir description influence the competition between gravity segregation and channeling due to heterogeneities. We illustrate for two example reservoir descriptions how the best choices of the viscosity and density mixing parameters, ωμ and ωρ, can be established by a special optimization procedure. A critical matching requirement is to minimize the errors in distributions of gas saturation. A saving of CPU time by a factor of 2000 is demonstrated for upscaled T&L coarse grid solutions in 2D. We make recommendations on how an upgraded T&L method should be used in reservoir studies.
Predicting Multiple Thermal Fractures in Horizontal Injection Wells; Coupling of a Wellbore and a Reservoir Simulator
Authors: Stevens D G , Murray L R , Shah P C
Published: December 2007

Injection well performance over the long term is often critically dependent upon how the well has been operated during its commissioning period. Whether the well is ultimately to be a seawater (or fresh water) injector or to be used for produced water re-injection, it may be beneficial to commission the well with a different water, probably at a different temperature, since this can have a marked effect upon the initiation of thermal fractures (more precisely these are usually in fact hydraulic fractures that have been initiated at reduced fracture gradients due to near wellbore reservoir cooling).

In long horizontal injectors it is likely that several separate thermal fractures may be generated, and their creation needs to be controlled and managed to ensure optimum well performance. To generate a procedure for the well commissioning requires us to be able to predict bottom hole injection temperature, rate and pressure variation along the horizontal (or highly deviated) section and couple this into a reservoir fracture model. Achieving this using separate models soon becomes impractical, requiring too may iterations between coupled problems.

This paper presents an overview of how an existing commercially available transient wellbore model has been coupled to a special purpose reservoir simulator, and how this has been applied to the modelling of multiple thermal fractures in horizontal injection wells. The paper also reports how the wellbore simulator has been modified to allow the prediction of depth dependent bottom hole temperatures. The paper will also comment on the application of this new coupled model to intervention work in production wells.
Computer Simulation of Carbonate Sedimentary and Shallow Diagenetic Processes
Authors: Matsuda Fumiaki , Saito Michinori , Iwahashi Ryotaro , Oda Hiroshi , Tsuji Yoshinori
Published: December 2007

A computer simulation model Facies-3D carbonate, developed by Japan National Oil Corporation, describes three dimensional carbonate facies based on water depth and current velocity in conjunction with estimated paleo-topography. The Facies-3D carbonate model also contains a module for evaluation of porosity changes in meteoric diagenetic environments. Output data are facies, thickness, and porosity for each grid for the simulation. The above-mentioned calculations are made at each step for the simulation period. Two simulation case studies were conducted using depositional and diagenetic models of the Pleistocene Ryukyu Group in the Irabu Island in the southern Ryukyus, Southwest Japan and the Upper Miocene Kais Formation in the Walio oil field in Irian Jaya, Indonesia.

The study of cores drilled in the Irabu Island clarified that the Ryukyu Group consists of two major lithofacies; the coral limestone facies of shallow shelf environment predominant in the eastern part of the island and the rhodolith limestone facies of deeper shelf environment predominant in the western part. Enhancement of porosity was observed beneath subaerial exposures. The Kais reefal carbonate reservoirs in the eastern Walio field were subdivided into seven shallowing upward cycles, and consist of the fore reef facies in the eastern edge of the area and the back reef facies in the central and western parts. The Kais reservoirs were affected by meteoric diagenesis.

The results of the simulations show that the Facies-3D carbonate model approximated to a high degree, the distribution of facies and the occurrence of porous intervals. The Facies-3D carbonate model can be applied as a tool for reservoir characterization in the field.
Solids Control - The Role Of Sedimentation
Authors: Louden L.R.
Published: December 2007

Louden, L.R., and Lawson, G.W., Members AIME, Oilfield Products Group, Dresser Industries, Inc.

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

A review of the role of sedimentation as applies to oilfield equipment for solids control is presented. By remembering that most all solid removal oilfield equipment except the screen function on an accelerated gravity principle, a proper understanding and use of the available equipment can be principle, a proper understanding and use of the available equipment can be obtained.

TEXT

In many processes it becomes necessary at some stage to separate one liquid from another, or solids from a liquid, or both — problems that have traditionally been solved by filtration or gravity sedimentation. Equipment presently in use in the oilfield for removing solids from mud for plastic viscosity and yield strength control is all based on sedimentation plastic viscosity and yield strength control is all based on sedimentation in one form or another, with one exception. Block diagram in Fig. 1 shows how oilfield equipment may be classified.

This exception, and it is important, is the vibrating screen, a sort of continuous filtration operation, to remove continuously the particles which would form the filter cake. Ironically, the vibrating screen is capable of removing a greater weight of drilled solids per dollar spent than any other piece of rig equipment. Yet it is probably misused and misunderstood by most people.

The remainder of the devices in common use all depend upon the sedimentation operation, and except for settling pits and ditches, these devices are based on enhancing the gravimetric forces to do this job faster, more efficiently, more economically, and in less space.

Often the term separation is used to describe an operation which is not separation at all. (The authors have fallen into this trap in this paper.) When the term separation is used in this paper, it means paper.) When the term separation is used in this paper, it means concentration of one phase or the other to acceptable limits.
Waterflooding the Navette "410" Reservoir
Authors: Simpson G.J.H.
Published: December 2007

Introduction

One of the earlier waterfloods in Trinidad was in the El Blanco area of the Nanette Field. The El Blanco area was discovered in March 1966 and rapid field development followed, Primary. production was by solution gas drive, and reached its peak during 1968. A reservoir engineering study was made with tee objective of increasing recovery, and a peripheral waterflood commenced in August 1969. Production response to the flood has been generally favourable..

GEOLOGY

The Navette Field is located in the Guayaguayare area of South East Trinidad, forming part of the south eastern flank of the Lizard Springs anticline (see Figure 1). Numerous cross faults occur in the field The El Blanco area, containing the largest fault block, covers the eastern one third of the area. (See Figure 2). Production is from Lower Gros Morne sands of Miocene age. The Lower Gros Morne Zone 4 is one of several Lower Gros Morne sands production in the area, and has been divided into an upper and lower zone, The lower zone consists of a massive fine-grained oil sand underlain by water, while the upper zone is characterized by alternating thin sands and shales. (See type log Figure 3). The sands were derived from a mixed source including volcanic rocks and deposited in the shallow marine, portion of a deltaic complex. The formation consists of vary fine grained sand medium grey, siltstone and shale.
Prospects For Natural Gas Utilization In Trinidad And Tobago
Authors: Ali B. , Houng C. Hee
Published: December 2007

Natural gas, primarily as a by-product of crude oil production has long been in use as a source of energy production has long been in use as a source of energy for refinery processing and electricity generation. During the past fifteen years, a nitrogenous fertilizer industry, based on natural gas, has also been developed. Recent discoveries of substantial reserves of gas in the off-shore areas provide a base for a more diversified industrial development of the country.

The paper reviews the historical development of gas production and utilization. The reserves position with production and utilization. The reserves position with respect to future availability is discussed. The potential for utilization in the following areas is discussed: potential for utilization in the following areas is discussed:as feedstock for manufacture of petrochemicals;as an energy source for large-scale and small-scale energy-intensive industries; andin manufacture of export energy products.

Some criteria for selection of the most desirable development route are suggested and a recommended priority rating is presented. priority rating is presented

Introduction

The discovery of substantial reserves of natural gas in be off-shore areas of Trinidad and Tobago, combined with encouraging prospects for the delineation of further reserves, has prompted investigation of the potential for usage of this gas for the country's industrial development. These studies have focussed on the use of the gas as a raw material for chemicals manufacture, as a source of energy for non-petroleum related industries and as an export energy product. product. This paper outlines the technical aspects of projects that have been identified for possible future development and suggests possible yard-sticks which may be used to aid decision-making with respect to selection of the optimum development route.

P. 79
Hydrocarbon Potential Of The Trinidad Area
Authors: Persad K.M.
Published: December 2007

It is now recognised that deltaic and associated sands, together with porous marine limestones, form the vast majority of the reservoirs in the major accumulations of hydrocarbons throughout the world.

The source of the hydrocarbons is now thought to be kerogen which is generated from the organic content of principally marine shales which are formed in or near the continental shelves.

The Trinidad area contains several sedimentary sub-basins, most of which consist in large of deltaic and associated sediments. These sediments, like most of the ancient deltas of the world, contain major reserves of oil and gas. Other less important reserves should occur in sporadic (time-wise) porous limestones.

The total probable reserves of the Trinidad areas exceed 7 billion barrels of oil and 35 trillion cubic feet of gas.

PETROLEUM POTENTIAL IN THE TRINIDAD AREA PETROLEUM POTENTIAL IN THE TRINIDAD AREA ORIGIN OF HYDROCARBONS

Current thinking assumes that in large part petroleum is generated in marine shales which are relatively rich in organic content Briefly, the organic content is changed under reducing conditions to kerogen or a kerogen-like substance which is the presursor of petroleum and petroleum like products. The kerogen petroleum and petroleum like products. The kerogen under the correct conditions of pressure and temperature, is then converted to hydrocarbons. These conditions are generally met if the shales are buried to several thousand feet in an area of normal temperature gradients. The hydrocarbons are generally thought to migrate soon After generation into whatever reservoir rocks lie nearby.

RESERVOIR TYPES

In broad terms two types of reservoir rocks trap over 95% of the known hydrocarbon accumulations. These are sandstones and limestones.

The majority of these accumulations are found to be those associated with deltas and porous limestones. The reasons for this are:They generally interfinger with organic marine shales which act as source rocks andThey are broadly either lenticular in nature or affected by growth faulting and/or folding caused by plastic flow of underlying shales, i.e. shale diapirism plastic flow of underlying shales, i.e. shale diapirism (in the case of deltaic sands) so that traps exist even before hydrocarbon generation and migration begin.

In other words, all the pre-requisites for hydrocarbon generation and trapping are generally present in areas of deltaic deposition or where limestone deposits interfinger with highly organic marine shales.

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Evaluation Of Cathodic Protection Systems For Offshore Structures
Authors: Edmonds A.T.G. , Higgins F.A.
Published: December 2007

A number of papers have been written and presented dealing with the detailed methods of calculating and applying cathodic protection to offshore structures. In this paper it is our intention to consider the technical qualities of the materials and systems available and compare these commercially.

The term offshore structures as used in this paper specifically refers to fixed drilling and production platforms and mobile drilling rigs.

Cathodic Protection

Cathodic Protection can be defined as the reduction or prevention of corrosion of a metal (e.g. steel) in an electrolyte prevention of corrosion of a metal (e.g. steel) in an electrolyte (e.g. sea water) by introducing an additional anode system from which electrical current will flow into the electrolyte and onto the corroding metal surface reducing or preventing the natural corrosion current flow from anodic areas to cathodic areas on that metallic surface. The protective current may be obtained from the use of highly electronegative materials such as magnesium, zinc or aluminium or by the use of relatively inert anodes with an external direct current power source. The former is termed sacrificial anode cathodic protection, the latter impressed current cathodic protection. protection. Steelwork Requiring Cathodic Protection Cathodic Protection should be considered for steel when it is:Totally immersed in water.Buried in the seabed or shore (i) in the bare condition or (ii) in the coated condition.Associated with or immersed in concrete when it is either (i) in the bare condition or (ii) in the coated condition.

Combinations of the above may also require cathodic protesion. protesion.

Cathodic Protection Systems

Sacrificial Anode Materials The following alloys are used as sacrificial anodes:Aluminium alloys.

These can be considered to be split into certain generic types. heat treatment aluminium zinc tin alloys, aluminium zinc mercury alloys and aluminium zinc indium alloys. Table 1 indicates some typical specifications.