bluuebunny/crossref_metadata_2025 huggingface dataset:
Tar Area Development in a Giant Carbonate Field in Saudi Arabia
Authors: Benedek Lajos , Ali Razally , AlGhamdi Humam , Alhuthali Ahmed H.
Published: June 2014

An ongoing focus area for Saudi Aramco is the optimum field development and depletion of the mobile oil in the tar area, which is limited in extent and occurs mainly along of the periphery of the southeast flank of the field. Unlike many tar mats in other fields, the tar in this field is patchy and has a complex distribution in the reservoir. In addition, areal and vertical tar extensions reveal great variations along with the existence of fractures in the area which imposes difficulties on the reservoir characterization as well as predicting fluid flow behavior.

The objectives of this paper is to present an overview of the tar infected areas, reservoir performance, formation evaluation results, reservoir characterization and modeling workflow to formulate the development strategy. Various tools were utilized such as NMR log, flow-meters, POPI analysis, PVT analysis, Pressure Transient and core analysis to better understand the tar and optimize the development strategy. This paper also documents the results of a recently drilled evaluation well and the proposed horizontal sidetracks performances as actual case studies.
Simulation of Formation Damage in Petroleum Reservoirs
Authors: Ohen Henry A. , Civan Faruk
Published: June 2014

A phenomenological model for prediction of petroleum reservoir permeability impairment by porous media, fine particles and liquid interactions is presented. The combined effects of clay swelling, external particles invasion, fines generation, migration and retention involved in permeability impairment are formulated. Deviation from Darcy flow as the flow paths are plugged and the variation of pore size distribution during plugging are considered. The model is tested for a variety of conditions. The magnitudes of the estimated model parameters are used to determine the relative contributions of various damage mechanisms. The estimated parameter values are shown to be valid beyond the range of the data used to estimate them. The successful match between the measured and predicted values of permeability variation and effluent fines concentration demonstrates the validity and the capability of the formation damage model.
Effect of Viscous Crossflow on Miscibility Development in a Two-Layer Flow System: Part I - Ternary Vaporizing Gas Drives
Authors: Pande K. K. , Orr F. M.
Published: June 2014

This paper examines the effect of permeability heterogeneity and viscous crossflow on ternary vaporizing gas drive displacements. Material balance equations that describe multicomponent, multiphase flow in a two-layer system are solved by finite differences for the case of maximum (vertical equilibrium) viscous crossflow between layers. The effects of interlayer permeability ratio and operating pressure on composition paths, composition and saturation profiles, and oil recovery are reported.

Fluid mixing due to viscous crossflow is shown to cause significant amounts of two-phase flow in displacements that would be multicontact miscible in the absence of crossflow. Although the induced two-phase flow reduces local displacement efficiency, viscous crossflow improves overall recovery because a decrease in mobility contrast between layers reduces channeling, and because some oil is moved from the low permeability layer to that with faster flow.
Investigation of a Cyclic Countercurrent Light-Oil/CO2 Immiscible Process
Authors: Hara S. K. , Christman P. G.
Published: June 2014

In this paper it is shown that CO2 can effectively displace oil from diatomite under countercurrent conditions. A simple model is presented which quantitatively matches the observed oil production. CO2 is postulated to contact the oil due primarily to diffusive transport, and the diffusion coefficient used is consistent with the results of CT scan experiment conducted to measure the liquid phase diffusion coefficient in diatomite.
Effect of Connate Water on Gas/Oil Relative Permeabilities for Water-Wet and Mixed-Wet Berea Rock
Authors: Narahara G. M. , Pozzi A. L. , Blackshear T. H.
Published: June 2014

Gas and oil relative permeabilities were measured on water-wet and mixed-wet Berea sandstone at various connate (initial) water satura- tion values, including zero, using the gasflood method. The centrifuge method was used to extend the measured oil relative permeability curves to lower total liquid saturations than could be achieved by gasflood. Composite cores were used in the gasfloods, whereas individual plugs were tested in the centrifuge.

The results show that gas and oil relative permeabilities are indepen- dent of the connate water saturation in water-wet and mixed-wet Berea sandstone provided certain conditions are satisfied.
Representation of a Horizontal Well in Numerical Reservoir Simulation
Authors: Peaceman Donald W.
Published: June 2014

The derivation of Peaceman's equation for the equivalent wellblock radius of a well in an anisotropic medium assumes that the grid is uniform and that the well is isolated, i.e., far from the grid boundaries. For a horizontal well, the assumption of being isolated may not be valid. The range of validity of Peaceman's equation is explored, using recent work of Babu and Odeh. If the reservoir is stratified or if the grid is not uniform, the assumptions underlying the equations of either Peaceman or Babu and Odeh are not valid, and a special program must be used to calculate the equivalent radius.
A Cellular Automaton Model for Flow in a Heterogeneous Reservoir
Authors: Lee S. H. , Chung E. Y.
Published: June 2014

This paper reports on the development of a 2-dimensional cellular automaton (CA) model to simulate fluid flow in porous media. In CA, simple rules of particle interactions at a lattice are used to simulate complex flow phenomena. Since the numerical operations involved are largely bit manipulation, CA can be potentially more efficient in memory usage than conventional methods, such as finite difference or finite element methods.

While other research on the use of CA to model porous media flow primarily focuses on Stokes flow at the pore level, with the intent of understanding flow at the core scale, this work concentrates on modeling Darcy flow in large heterogeneous fields. Permeability variations and anisotropy are modeled by a distribution of "soft scatterers" and "directional scatterers". Collision of incoming particles with scatterers is a stochastic process. Anisotropy is modeled via a preferred direction of collision between the directional scatterers and incoming particles

The CA model is verified through the study of single-phase flow in porous media. Simulation results obtained from this CA model show that particle flow rates are linearly proportional to pressure gradient (pressure is modeled through particle density in CA), and permeability is linearly correlated with scatterer density over a certain domain. Therefore, the CA model can be used to predict Darcy-like flow. It is shown that heterogeneity is modeled properly by varying the density of scatterers.

In addition to the single fluid model, a model with two fluids with identical physical properties has also been developed to study dispersion characteristics of a CA model. In the numerical simulation results, the transverse diffusivity converges to the theoretical constant, but the longitudinal diffusivity increases with time. Finally, extension of the current model to a more general case (i.e., three-dimensional, multiphase flow) is also discussed.
Orthogonal Adaptive Grid Generation with Fixed Internal Boundaries for Oil Reservoir Simulation
Authors: Sharpe H. N. , Anderson D. A.
Published: June 2014

The generation of boundary conforming, orthogonal, smooth curvilinear grid systems for regions containing internal boundaries, which can also cluster dynamically to physical solution gradients, is of major importance to reservoir simulation. This paper develops a practical methodology for achieving these objectives for two dimensional problems, with extensions to three dimensions. It is based on extending elliptic mapping methods to parabolic ones and the use of equidistribution schemes.
An Adaptive Variational Finite Element Method for Computing Coupled Porous-Media Problems with Moving Fronts
Authors: Kececioglu Ifiyenia
Published: June 2014

An adaptive deforming-grid mixed-variable finite element method for solving two-dimensional porous-media transport problems governed by a system of coupled nonlinear partial differential evolution equations, is presented. The advantages of this methodology over standard fixed-grid formulations in improving solution accuracy and yielding better computational stability characteristics are discussed and demonstrated through solution of a representative set of problems. Accordingly, extremely accurate solutions were computed not only for the primary variables but also their fluxes, with a very small fixed number of deforming and moving finite elements, for a set of transient high Péclet number porous-media convection-diffusion (continuous moving front) problems and also for the front motion (discrete moving front) during resaturation by water of a porous rock.
Reinfiltration in Fractured Porous Media: Part 1 - One Dimensional Model
Authors: Firoozabadi Abbas , Ishimoto Koichiro
Published: June 2014

Conventional fractured reservoir simulation models often neglect some fundamental aspects of multiphase flow in fractured porous media. Reinfiltration of the drained liquid from the upper blocks to the lower blocks is a key process which is often neglected. In this study, we present a theory of reinfiltration in fractured porous media in a one-dimensional (1-D) space. Based on this theory, it is established that the rate of drainage in a matrix block is always less than or equal to the reinfiltration rate. This implies that the drained liquid (for a gas-liquid system) from an upper block, rein-filtrates to the lower block and does not flow through the fracture network.
Transport Coefficients for Compositional Simulation with Coarse Grids in Heterogeneous Media
Authors: Barker J. W. , Fayers F. J.
Published: June 2014

Novel transport coefficients (α-factors) are introduced in the flow terms of a compositional simulator to model the interaction between phase behaviour and reservoir heterogeneity within coarse grid blocks. They are successfully used to model both lean and rich gas injection in stochastically-generated, heterogeneous reservoir cross-sections.
On the Effect of the Electroless Nickel-Phosphorus(Ni-P) Coating Defects on the Performance of This Type of Coating in Oilfield Environments
Authors: Mainier Fernando B. , de Araújo Marcelo M.
Published: June 2014

In the eighties the use of electroless nickel-phosphorus(Ni-P) coatings was largely increased in many industrial segments. In the oil industry this kind of coating has a particularly large applicability due to its outstanding resistance to CO2, H2S and aqueous brines. Therefore, it has been largely applied to valves, section pumps, production tubings, and other equipment. Nevertheless, laboratory tests performed have shown that it is essential to evaluate the quality of the coating in order to assure its field performance for it is dramatically affected by surface defect. In this paper several problems that occasionally occur in Ni-P coatings are presented. The following items of the coating are evaluated: nickel and phosphorus content, hardness, adherence, porosity, discontinuities, thickness and uniformity.
Numerical Simulation Study of Cyclical Processes of In-Situ Combustion and Steam Injection
Authors: Colonomos P. , Rodriguez H. , Villalba M. , Zerpa L.
Published: June 2014

This paper presents a conceptual study of the numerical simulation of thermal stimulation processes such as the injection of steam and the in situ combustion using oxygen. A comparison is made of the production behavior of a representative well of heavy crudes in the Venezuela Orinoco Belt under an intermittent regime of in-situ combustion and a cyclic steam injection scheme. The production mechanisms responsible for the additional recovery are analyzed, as well as the effects of various parameters on the recovery of oil. The purpose of the study was to determine the technical feasibility of a cyclic in-situ combustion processes with oxygen to increase the production potential of heavy oil reservoirs.

A compositional thermal simulator with a tridimensional model was used for the study. This was done under conditions comparable with those existing in cyclic steam injection projects in the Hamaca field of the Orinoco Belt.

The results show that in both cyclic processes, under a constant energetic base, there is a similar increment in the production of oil. The sensitivity analyses show that on incrementing the rate of injection there is an increase of production although the process efficiency decreases. In the case of in situ combustion, the pressure of injection and temperature of injection did not affect the recovery obtained during the process. Furthermore, one of the principal mechanisms of production which acted during the cyclical combustion process is the dissolution of the carbon dioxide in the crude.

Our study point to the technical feasibility of the cyclic combustion process with oxygen as an alternative when the injection steam cannot be applied in heavy crude reservoirs.
A Basic Study of the Interaction of Steam, Hot Water and Oil in Water Emulsion
Authors: McKay A. S. , Redford D. A.
Published: June 2014

Eighty percent quality steam at 200°C and 200 psi was injected into a horizontal cylindrical simulator 100 cm in length and 25 cm in diameter with a frac sand communication path along the central axis. Injection and production fluid temperatures and pressures along with the temperatures of 35 thermocouples located in the porous sand were recorded every five minutes. Whenever steam is present the thermocouple temperature can be converted to the saturated steam vapor pressure which is also the same as the fluid pressure regardless of the amount or quality of the steam. It was possible to plot steam profiles at various times which were the dividing line between fluid that contained very little steam and fluid that was 100% hot water and bitumen. Most of the bitumen was mobilized in the hot water zone between the steam profile and the 120°C profile. The 20% oil cut oil in water emulsion that was produced through the communication path had sufficiently high viscosity to divert the injected steam and hot water into the cooler immobile bitumen tar sand zones.

This experiment has been very helpful in developing improved thermal processes for the in situ recovery of bitumen and heavy oil.
New Relationships for Slug Sizing in Radial Two-Phase Displacement
Authors: Allen Elise
Published: June 2014

An experimental study was made of the unconfined radial displacement of miscible Newtonian and non-Newtonian fluids in a Hele-Shaw cell and a narrow packed radial cell. The results show that viscous fingering in uncnnfined radial flow is not simply a function of the mobility ratio for a given set of displacement conditions. Both the displacement efficiency and the dimensionless size of the dispersion zone are power-law functions of the displacement distance for Newtonian and non-Newtonian fluids. The instability of non-Newtonian displacements is a strong function of the fluid rheology, and of the degree of heterogeneity in the porous medium. The ratio of the dispersion zone width to the mean radius of the interface can be estimated within ± 80 percent from Koval's theory for flow in a slit. However, the results for flow in the packed cell suggest that the appropriate slug size for these displacements may be substantially underestimated from the existing relationships (by up to 600 percent). New equations are proposed to describe the fingering behaviour in radial flow, and a correlation is provided for determining the displacement efficiency of Newtonian fluids in a slit (fracture).
Polymer-Enhanced Foams Part 1: Laboratory Development And Evaluation
Authors: Sydansk Robert D.
Published: June 2014

A laboratory study was conducted to identify pertinent properties and features of polymer-enhanced foams (PEFs). In addition, initial development of acrylamide-polymer oil-recovery PEFs was completed. Polymer addition to the aqueous phase of conventional foams resulted in foams of enhanced viscosity and stability. Based on findings of this laboratory study, PEFs appear to be attractive conformance-improvement fluids and attractive mobility-control fluids for use in naturally fractured reservoirs. The acrylamide-polymer PEFs promoted exceptionally high effective viscosities and were much more stable than conventional oil-recovery foams. Effective viscosities of the PEFs were comparable to the viscosities of the polymer solutions from which the PEFs were derived. PEFs exhibited shear-thinning viscosity behavior which makes them attractive for use as mobility-control fluids.

The following parameters relating to PEFs were studied: polymer properties and concentration, surfactant types and concentration, aqueous phase viscosity, absolute pressure, foam quality (volume fraction gas), gas type, stability in glassware, rheology and the effect of shear, critical pressure gradient for flow, and briefly, temperature and brine makeup chemistries. Stability of PEFs in glassware was much better than that of counterpart conventional foams. PEFs were successfully formulated over a broad range of foam qualities, and the viscosity performance of the PEFs was highly insensitive to foam quality. A PEF was more efficient than brine or two polymer solutions at displacing a viscous oil (25:1 oil:water viscosity ratio) in an ideal fracture model. Much of the experimental work involved constant-differential-pressure flooding experiments performed in high-permeability sandpacks. PEFs were successfully formulated with nitrogen, carbon dioxide, and methane as the gas phase.

The study was limited to PEFs for application within fractures of naturally fractured reservoirs and to PEFs that are to be generated above-ground prior to injection. Only the addition of acrylamide polymers to foams was considered. A large majority of the PEFs were formulated with alpha olefin sulfonates as the foaming surfactant.
The Impact of 3D Seismic, New Well Data, and a Review on the Development Plans for a Mature Field
Authors: Chung K. S. , Holtam V. R.
Published: June 2014

Peak production from the Baram Field was ca. 60,000 b/d in 1974. However, ly 1987, production had declined to below 10,000 b/d. In 1987, the Baram Field Joint Venture Study Team identified significant scope for further development, with 132 MMstb of reserves proposed for development from a senes of new platforms and revisits to existing platforms. To firm-up diese reserves, 3D seismic was acquired over the whole Baram Field in 1988.

Based on the new 3D seismic based maps and new data from recently woiked over wells, a review of reserves was carried out and the scope for further development revised. Based on this woik, significant additional reserves were identified, while the scope of individual projects also changed significantly. The reserves planned for development now stand at 191 MMstb, while the number of proposed new platforms has been reduced.

This paper discusses the 3D seismic data set and Interpretation problems as well as the impact of the 3D seismic on the structuie maps. The review of reserves is discussed, including the performance re views and simple Simulation studies. The paper shows how 3D seismic together with new well data and a review of the performance can have a significant impact on the development plans for a mature field.
Statistical Secondary Recovery Model
Authors: Barbieri Roberto R.
Published: June 2014

A secondary recovery model has been developed to predict waterflood performance for different reservoir properties and design conditions. A causal model based on simple and multiple regression equations uses eight input variables to estimate injection rate, ultimate secondary reserves, response time and yields peak oil rate, peak year and the production profile as a function of time. It is used for secondary reserve booking, to develop production profiles for project economics and authorization for expenditures and to assess technical risk by means of the simulation technique.
State-Of-The-Art In The Matrix Stimulation Of Horizontal Wells
Authors: Frick T. P. , Economides M. J.
Published: June 2014

Horizontal wells have created a number of new challenges including the appropriate reservoir selection, drilling and completion techniques and, recently, stimulation.

The ever lengthening horizontal sections pose considerable problems in fluid distribution, required stimulation fluid volumes and optimization of stimulation versus completion. The pre- and posttreatment productivity indexes, and stimulation execution requirements are the essential elements of the technology presented here.
Tracer Injection Simulations by Finite Element Methods
Authors: Loula A. F. D. , Guerreiro J. N. C. , Ribeiro F. L. B. , Landau L.
Published: June 2014

In this paper we describe a methodology to simulate tracer flow, using finite element methods. After time domain discretization, classical Galerkin's method is used to approximate the pressure equation and then the velocity is accurately calculated through pressure gradients, Darcy's law and a post-processing technique. To solve the concentration equation, we use a streamline upwind Petrov-Galerkin (SUPG) method in two steps. An h-adaptive finite element technique is also adopted. Numerical results are presented illustrating the applications of these techniques to a five spot geometry.
A Multigrid Procedure for Local Grid Refinement in Oil Reservoir Simulation
Authors: Rodrigues J. R. P. , Dickstein F.
Published: June 2014

We discuss local grid refinement procedures for reservoir simulation, including local timestepping, which means the use of different time step sizes in the coarse and refined regions. A non-linear multigrid algorithm is proposed for solving the coupling between coarse and fine meshes. This approach does not need to solve for matrices with complex structure, it does not employ any relaxation parameters, it is well suited for parallel processing and it can be easily implemented in existing simulators.

The proposed techniques were implemented in a black-oil simulator and tested in complex problems described in the literature. The results show the ability local grid refinement has to model the behaviour in the vicinity of wells. The coupling algorithm has shown to be robust and efficient, allowing a significant reduction in CPU time when compared to regular and fine meshes. The local timestepping procedure has shown to be attractive specially in cases where the number of grid blocks in the coarse mesh is large when compared to the refined regions. This situation is typical of field studies.
Multiphase Transportation of High Waxy Crudes
Authors: Rai R. , Sarkar B. , Dalai V.
Published: June 2014

There is a general concern in the oil industry regarding the flow of crudes at temperatures below the pour point. However, this concern is not valid as long as adequate pressure is available to maintain the continuous flow. Practically, pumping of waxy crudes below the pour point is quite common for the transportation of such crudes. Multiphase waxy crude is associated with dissolved and free gas; water can be present either as free water or in emulsion form; and gas-liquid flow pattern such as slug flow may occur with turbulent mixing. All these tend to decrease the congealing of the waxy crudes.

An analysis of a case history has been carried out on the possibility of congealing of high waxy multiphase flow lines considering above governing parameters. The analysis includes normal operating condition as well as shut down and start up of the pipeline.

The analysis confirmed that the congealing of crude in pipeline should not be concluded simply based on the pour point of the dead crude. This is even more relevant in the case of multiphase transportation. Based on the recommendations for the present case, a marginal offshore field of India was put on production and is producing since then without any major problem. This has eliminated a recurring cost of US $ 0.4 million per year on chemical treatment apart from capital cost on other requirements of chemical dosing.
Workforce Participation in Safety Case Preparation
Authors: Forrest J. E. , Reisz J. D.
Published: June 2014

The requirement in the United Kingdom for Safety Cases to be prepared and submitted stemmed from the Cullen Inquiry into the Piper Alpha disaster. The Safety Case is the means for an operator or owner of an installation to demonstrate how safe design and operation is achieved. An important part of the preparation process is to consult relevant members of the workforce.

This paper discusses how the workforce have been involved in the preparation of Safety Cases. The experience gained in submitting Safety Cases for 9 onshore and offshore installations over the last 2 years is covered with particular emphasis on the role played by the safety committee system, plant and field personnel (staff and contract) and line management. The installations range from large manned oil and gas platforms and an associated onshore gas processing plant, to small single well normally unmanned gas platforms.

The main benefits of workforce involvement have been found to be in the participation process itself. This leads to a higher level of workforce "ownership" of the Safety Case. It is concluded that this process has helped to achieve even better workforce communication, understanding and co-operation on safety issues than in the past.
Lessons Learned in a Large Full-Field Simulation Study
Authors: Williams M. A. , Toronyi R. M. , Bu-Hulaigah E. H.
Published: June 2014

This paper presents a retrospective on the building of a combination vertical front-tracking and energy model. This effort involved the development of a new geologic description and the construction and validation of a full-field model incorporating coning and surface facility simulation. This was the most complicated and detailed model in the 35 years of numerical simulation on the Safaniya reservoir and contained 61,257 active grid cells and 500 wells with over 2,000 completions. This model represents a fully-integrated geologic and engineering approach, employing all core data, openhole and pulsed neutron well log analyses, sedimentological interpretations, RFT and flowmeter results, and pressure buildup tests to provide the best means available to capture reservoir behavior on a field-wide scale. This paper presents the lessons learned through this extensive simulation project.
Optimized Electric Submersible Pumping to Extend Economic Oil Production in a High Water Cut Environment
Authors: Galles D.J. , Larson J.B.
Published: June 2014

The economic life of the Equity Oil Company operated lease in the Ashley Valley Field of Uintah County, UT has been extended significantly from efficient use of electric power, Early efforts to reduce power consumption inefficiencies included replacement of flowlines to lower surface backpressure, installation of a central capacitor bank to eliminate power factor penalty payments and a well respacing project. This paper shall focus on recent efforts concerning submersible pumping optimization including the use of increased efficiency stage and motor designs and proper equipment selection to operate at maximum efficiency.

Operating Environment

The primary reservoir in the Ashley Valley Field is Weber sandstone of Pennsylvanian age at an average depth of 4,200 ft. The Ashley Valley Field is on a northwest - southeast trending anticline located in the Uintah Basin of northeastern Utah. The field was discovered in October, 1948 and is recognized as the first commercial oil discovery in Utah. A structure map is presented as Figure 1.

Initially, all wells flowed and were essentially free of water. No initial gas cap was present in the reservoir. The active fresh water drive resulted in the installation of submersible pumps on the Equity lease in 1960. Production performance is presented as a water-oil ratio (WOR) versus cumulative production plot in Figure 2. Average daily production is currently 85 BOPD and 35,100 BWPD from four wells. Produced fluids from all wells flow into a 3,000 bbl gunbarrel separation tank and through a series of retention pits for final separation. Chemical injection at the wellhead also aids in separation of oil from water. The discharge from the final retention pit is a source of agriculture irrigation water. Additional operating environment data is provided as Table 1.

Life Expectancy and Failure Mode of ESP's

Field History/Failure Modes. A field failure history quantifies run times, operating conditions and failure modes in Tables 2 and 3.
Natural Controls on NORM in Produced Water from Texas Reservoirs
Authors: Fisher R. Stephen
Published: June 2014

Naturally occurring radioactive materials (NORM) in produced water; sludge, and scale from Texas oil, gas, and geothermal wells increase concerns for worker safety as well as costs for handling and disposal. We combined published data, new analyses, and geochemical modeling to explore geologic, geochemical, and geographic controls on this radioactivity.

NORM are caused primarily by 226Ra and 228Ra, the alpha-decay products of 238U and 232Th, respectively, in water and barite (BaSO4) scale. Local variations in reservoir lithology are a major control on NORM levels because of the geologically short half-lives of the Ra isotopes, slow basinal fluid-flow velocities, short transport distances during reservoir production, and the naturally heterogeneous distribution of U and Th in reservoir rocks. High salinity in produced water primarily controls Ra mobility in solution. Formation water composition and reservoir temperature determine the type and amount of scale that can form. Scale mineralogy and Ra/Ba and Ba/SO4 solute ratios in turn determine the Ra activity of scale. Analysis of our data base reveals several associations of NORM activity with reservoir and formation water characteristics. These associations can be used to predict NORM levels at the play, field, and reservoir scale.
Reservoir Management: Principles and Practices
Authors: Al-Hussainy Rafi , Humphreys Neil
Published: June 2014

Reservoir management is a method that seeks to maximize the value of a hydrocarbon asset. However, different companies and authors have differing approaches to reservoir management, and no generally accepted definition of this activity exists within the industry. This paper reviews some of the origins of reservoir management techniques and provides an overview of reservoir management principles. Reservoir management is directed toward maximizing the value of a hydrocarbon asset. The value of any reservoir is defined differently by different people at different times. To develop a reservoir optimally to maximize its value, the exact meaning of "value" must be clearly understood.
Norne Field Development - Fast Track From Discovery to Production
Authors: Steffensen Ivar , Karstadt Per Ivar
Published: June 2014

The Norne Field was discovered in December 1991, and is one of the largest oil discoveries on the Norwegian Continental Shelf the last decade. In order to improve economy and maintain momentum in the development of the field, a novel approach of managing large and complex projects was initiated. This included amore integrated approach, with parallel execution of activities, standardisation and close relations to contractors, licence partners and authorities.

This paper review the reservoir description and development, the concept evaluations and the new approach to project management.

Introduction

The Norne Field is located in the blocks 6608/10 and 6508/1 in the Nordland II area of the Norwegian Continental Shelf. The field is located 200 km from the shore and 85 km northeast of the Heidrun Field (Fig. 1). The water depth in the area is 370 to 390 metres.

The Norne Field was discovered in December 1991 by well 6608/10-2. The discovery well contained a total hydrocarbon column of 135 metres; a 110 metresoil column with an overlying gas cap. An appraisal well, 6608/10-3, was drilled on the northern part of the Norne structure early 1993. The well confirmed the results from the discovery well, and proved the extension of the field to the north. Well 6608/10-4 was drilled in a structure 2-3 km east of the Norne Field early 1994, and discovered a minor oil accumulation.

Time from discovery to production and investment costs are major factors influencing the economy of a field development. In the past, the time from discovery to production for field developments comparable to the Norne Field(water depth, reserves, etc.) have been 8-10 years. The Norne development project was established in the spring of 1993 with objectives to minimize time from discovery to production, and to reduce the investment costs with 30-40%compared to the current established level in Norway. To achieve this, a new approach to project management was required.
Application Of The Technique Of Multi-Fracture Fracturing Using Diverting Agent
Authors: Dingxiang Xia , Jiaqi Wang , Xiuchen Wang , Ximin Chen
Published: June 2014

In Daqing Oilfield, since 1988 1524 oil wells have been fractured by this technique. This is 21.4 percent of all fractured oil wells. The average oil production improvement of each well is 15.0 t/d, a 1.5 fold increase over conventionally fractured wells. The cumulative oil production improvement is 340.3 × 104 tons 203 water wells were fractured by TMFUD, 33 0 percent of all the fractured water injection wells The mean water injection improvement per day is 80.8 m3/d, and the cumulative water injection rate is increased by 146.6 × 104m3. The multifracture fracturing technique can be used to stimulate low permeability thin interlayers and as many as 6 to 9 independent sub-layers without moving the string.
Progressive Production Technology in Complicated Dispersed Small Oil and Gas Fields
Authors: Tiesen Sun , Shulin Su , Houfa Liu , Shanbin Du
Published: June 2014

Producing experience in complicated, dispersed small oil and gas fields in the west peripheral area of Daqing oilfield has led to development of a system of progressive production technology. Experience shows that this technology system is feasible and of good practical value to the production of a complicated small oilfield.
Pilot Test of Water Alternating Gas Injection in Heterogeneous Thick Reservoir of Positive Rhythm Sedimentation of Daqing Oil Field
Authors: Baojun Feng , Xingjia Du , Cai Yu
Published: June 2014

Immiscible WAG injection was successfully used to enhance the oil recovery in the thick, heterogeneous reservoir in the east of Beier area of Daqing oil field. After a five year test period, the water cut is basically stable and production is continuously increasing. The recovery factor is now more than 3% higher than the ultimate recovery factor by water injection, and ultimate recovery is predicted to be more than 8% higher. Changes have taken place in the water entry profile of the injection well. Gravity segregation occurs in the reservoir. Areal sweep conditions are improved and the thickness of liquid production increased.
Well Logging Interpretation Method for Oil-Water Two Phase Flow
Authors: Yulong Wang
Published: June 2014

The production profile can be obtained with a continuous flow meter and a gradiomanometer. Slip and other factors in the vertical string for two phase (oil-water) flow, affect the data and make it very difficult to interpret. To solve this problem, studies were made in a simulation well of the relationship between the rotary speed of the spinner and the water holdup, and the ratio of the apparent velocity to the average fluid velocity and water holdup. Four relationship charts and interpretation programs were developed A total model of the simulating experiment was built, which can interpret multiple zone oil/water production rates to draw their profile map, and quantitatively interpret oil bubbles moving upward, and interpret the reverse rotation of the spinner in the vertical string. The data obtained from 20 wells show that the method has high resolution so that low producing layers can be detected and quantitatively interpreted. Also, intra-formationaJ interpretations for thick formations can be made. In conjunction with the water intake profile of the surrounding injection well, a plot of water-injection versus oil-production can also be drawn.
Hydraulic Fracture Diagnostics
Authors: Warpinski Norman R.
Published: June 2014

Fracture diagnostics can provide important information on fracture geometry that can be used to improve stimulation effectiveness and reduce costs. Several cost-effective diagnostics already exist, and the technology for obtaining a full image of the fracture is progressing to the point of practical application.

Introduction

Hydraulic fracturing is an interesting technology that has evolved to a mature, complex level; is critical to the economical production of hydrocarbons; and is a significant portion of the well-development cost. Nevertheless, it is still not understood fully or, at least, is interpreted poorly. Some may argue that the physical laws governing fracturing are known and fracture models are accurate, but the emergence of "new mechanisms" every few years (e.g., scale-dependent fracture toughness, complex fracturing, dilatancy, and convection) suggests that the basic physics incorporated into models has not been as comprehensive as required to model a fracture fully.

The reasons for the uncertainty surrounding the fracturing process are quite clear. The Earth is a complex, discontinuous medium, and historically there has been limited technology for observing or inferring fracturing results. Nothing can be done about the complexity of typical reservoirs in the Earth, and one can expect that difficulties with complexity will increase as more marginal reservoirs are exploited. On the other hand, diagnostic capabilities continue to improve and technology is reaching the point where fracture diagnostics can be applied by the average producer in problem situations, in new fields, or for validation of new fracturing techniques.

Furthermore, as operators continue to work in difficult, complex lithologies, it becomes clear that stimulation problems cannot be solved without some diagnostic data from which judicious decisions can be made. Diagnostics cost money, but trial-and-error approaches often cost more money and can result in lost wells. Decisions on well spacing, field layout, sand concentrations and volumes, number of zones that can be stimulated in one treatment, optimum perforation schedule, and many other operational parameters can be made correctly if the proper diagnostic information is available in a timely manner. This article briefly reviews the status of stimulation diagnostics and provides some information on newer technology that is becoming available. Some of these techniques could provide information that will improve production or reduce costs.
Engineering Core Analysis
Authors: Unalmiser Servet , Funk James J.
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Introduction

Core analysis has come a long way from the days when reservoir productivity was determined by blowing through a piece of cable-tool-produced core. Our tools and methods for drilling and core analysis have changed, but our interests have not. The reservoir-rock properties that determine hydrocarbon production, the variation in these properties, and how these properties affectultimate recovery are still of primary concern. Properly engineered core analysis provides a direct measurement of these reservoir-rock properties and is an essential step in formation-evaluation, reservoir, and production engineering. Fundamental core-analysis measurements are unchanged, but advances provide the ability to test at reservoir conditions and to acquire simultaneous measurements of reservoir-dependent properties. Core analysis today uses X-ray computerized tomography (CT) to determine two- and three-dimensional (2D and3D, respectively) porosity distributions, while continuing to apply Boyle's law and Archimedes' principle to determine porosity. Mercury injection is used routinely to describe pore-throat distributions, but nuclear magnetic resonance(NMR) is becoming a popular method to delineate relationships between poreradii and permeability. This review addresses some recurrent concerns of core analysis as well as some new approaches and insights that are part of the physical reservoir model determined by core analysis. Refs. 1 through 6 provide more information on the subject.

Coring and Field Operation

Reservoir studies seeking to interpret and define both geological and engineering parameters dictate the core-analysis program. Core analyses mustintegrate with field and production data and eliminate reservoir uncertainties that cannot be addressed with log, well-test, or seismic data. These requirements define the coring objectives that, in turn, control coring fluid, tools, and core handling. In most cases, these objectives cannot be obtained with core retrieved in a single well. Coring is thus an integral part of the reservoir-life-cycle process, with cored wells selected to verify or provide maximum information for the current geological, engineering, or production model of the reservoir.
State of the Art of Gas/Liquid Cylindrical-Cyclone Compact-Separator Technology
Authors: Shoham Ovadia , Kouba Gene
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

The petroleum industry has relied mainly on conventional, vessel-type separators to process wellhead production of oil/water/gas flow. However, economic and operational pressures continue to force the industry to seek less expensive and more efficient separation alternatives in the form of compact separators, especially for offshore applications. Compared with vessel-type separators, compact separators, such as the gas/liquid cylindrical cyclone(GLCC), are simple, low-cost, low-weight separators that require little maintenance and are easy to install and operate. However, the inability to predict GLCC performance adequately has inhibited its widespread deployment. Current R&D is aimed at creating the necessary performance-prediction tools for proper design and operation of GLCC separators. This paper presents the status of the development of the GLCC, the state of the art with respect to its simulation and design, and current successful and potential applications.

Introduction

The GLCC (Fig. 1) consists of a vertical pipe with a tangential inclined inlet and outlets for gas and liquid. The tangential flow from the inlet to the body of the GLCC creates a swirl that produces centrifugal and buoyancy forces on the fluids that are an order of magnitude higher than the force of gravity. The combination of gravitational, centrifugal, and buoyancy forces separates the gas and liquid. The liquid is pushed radially outward and downward toward the liquid exit, while the gas is driven inward and upward toward the gasoutlet. The low-cost, low-weight, compact GLCC separator offers an attractive alternative to the conventional vessel-type separator. A size comparison between the GLCC and conventional vessel-type vertical and horizontal separators has been conducted recently for a typical field application with oil and gas flow rates of 100,000 B/D and 70,000 Mscf/D, respectively, at 100 psig. For this case, the required GLCC inner diameter and height are 5 and 20 ft, respectively. These dimensions are approximately one-half of the corresponding dimensions of the required conventional vertical separator (9 x 35 ft) and about one-quarter of the dimensions of a conventional horizontal separator (19x 75 ft).
Managing Data Assets To Improve Business Performance
Authors: Lesslar P.C. , van den Berg F.G.
Published: June 2014

A project to improve integration of data and computer applications for exploration, appraisal, and field-development planning is ongoing at Sarawak Shell Bhd. An increased awareness of the importance of data as an asset has resulted in definition of a project aimed at improving the exploitation and management of this asset. This is expected to affect business through increased staff productivity and realization of new development opportunities through better subsurface interpretation and field management.

INTRODUCTION

During 1995-96, Sarawak Shell underwent an organizational review to transform itself into an asset-based organization. Integrated asset teams that encompass exploration, development, and reservoir-management activities were formed. During the review phase, subsurface- and surface-data management were identified as key areas that needed to be addressed and improved. Small teams were subsequently set up to define the scope and terms of reference for these projects. This paper describes the objectives and setup of the Subsurface Data Integration (SSDI) project.

PROJECT MANAGEMENT AND LOGISTICS

The goal of the SSDI project is to address the following main activities:data integration, project and corporate databases, applications- portfoliomanagement, data ownership, and procedures. Fig. 1 shows the data challenge, a key value driver for the initiative. The data challenge is from an in-house Shell study that suggested that technical professionals spend 60% of their time looking for data. The SSDI project team coordinates and drives the project and helps the business units implement the improvements. A companywide steering group makes key decisions with representatives from these business units and technical service groups. Fig. 2 illustrates the relationships between the project team, the steering group, and the asset teams. The activities carried out as part of the project are facilitated and supported by the project team but owned and driven by the asset teams through the steering group. This ensures that business requirements drive the tasks and priorities for the project team.
The History and Success of Liquid CO2 and CO2/N2 Fracturing System
Authors: Gupta D.V. S. , Bobier D. M.
Published: June 2014

Liquid CO2 system has been pumped as fracturing fluids in North America since the early 1980s and the liquid CO2/N2 system from 1994. The fluids have been used in over 1000 wells in a variety of formations and in wells of permeabilities from 0.1mD to 10 Darcies, depths in excess of 3000 meters and BHT from 10 to 100 degrees Celsius. The chemistry and physics of these fluids are very intriguing and are described. These include the thermodynamics of the fluids and the physical properties of density and viscosity of these fluids. The effect of compressibility and the transient effects on fluid leak off are discussed. The suggested process for proppant placement with these low viscosity, non-damaging fluids are described. This includes the density and turbulent effects. The design model considerations for the design of the fracturing jobs with these fluids are also summarized. Operational considerations of pumping these low temperature fluids in the field are detailed. A summary of the field use of these fluids is described.