bluuebunny/crossref_metadata_2025 huggingface dataset:
A Unified Theory on Residual Oil Saturation and Irreducible Water Saturation
Authors: Valenti Nick P. , Valenti R. M. , Koederitz L. F.
Published: December 2007

In many mature fields, there is a growing debate as to how much of the remaining oil is mobile in the unswept regions versus immobile in the swept regions. Log measured oil saturations behind the flood front are substantially lower than the residual oil saturations measured from special core analysis. In order to explain this contradiction, data from several fields is analyzed with special emphasis on capillary pressure. The concept of irreducible water saturation, connate water saturation, residual oil saturation and "critical water saturation" are discussed. The conclusions which are supported by experiment and theory, have substantial commercial implications concerning the location of remaining reserves – in the immobile region or the unswept region. Based on these results, entirely different depletion strategies should be recommended. The concepts presented in this paper help to explain, in part, why reservoirs continue to produce past their forecasted abandonment, and why perfectly "history-matched" reservoir simulation models tend to grossly under-estimate incremental reserves through improved sweep efficiency. These issues are critical in optimizing the depletion strategy of oil and gas reservoirs.

The discussion throughout this paper refers to an oil-water system in a water-wet or mixed-wet reservoir; however, these basic concepts can be applied to gas-water systems, three-phase systems, or other immiscible displacement systems and and oil-wet reservoirs.
An Alternative Method to Calculate Reserves Distribution for Geologically Dependent Layers
Authors: Wang Shie-Way
Published: December 2007

This study presents an alternative method, which can be used to estimate conditional probabilities and reserves distributions for geologically dependent layers, horizons or fault blocks. This paper contains two examples to demonstrate the methodologies. Example 1 illustrates how to analyze a drilling prospect using an existent method to determine the reserves distribution and the probability of each possible outcome for a project with three dependent layers. Example 2 presents an alternative method which can be used to calculate all intermediate conditional probabilities of dependent events and how to design Monte Carlo simulation in order to determine P10, P50, P90 reserves distribution. Comparison of these two methods and estimation of conditional probabilities for more than three layers is discussed in the end of this paper.
Applied Production Optimization: i-Field
Authors: Sengul Mahmut , Bekkousha Miloud A.
Published: December 2007

Middle East hydrocarbon reservoirs are getting matured. The remaining recoverable reserves are in geologically complex challenging areas, poor reservoir quality, dynamical fluid properties are varying from one zone to another drastically. Under these circumstances it is very difficult not only increase but also sustain the current hydrocarbon production. There is an increasing need for introducing new technologies and fresh look to wells’ deliverable potentials by applying state of art tools and processes.

The current and projected state of the E&P industry finds both operating and service companies squeezed by volatile oil prices and higher operating costs. Oil companies are responding to these market dynamics by re-engineering their workflow processes seeking new ways to reduce Capex and Opex, focusing their core business activities. Applied production optimization is a step forward for providing new enabling tools to achieve the intelligent field (i-Field) concept. The main elements of the model are as following: Monitoring through subsurface and surface sensorsReal time or near real-time data deliveryIntegration of data at field level, generate local tasksSend feedback to field via remotely operated toolsDistributed decision making via expert systemsInterface with corporate portal for live MISBusiness process automation

The enablers of the applied production optimization process are; downhole reservoir and production sensors and integration with surface data at well site. The seamless passage from data to production model has been achieved through the combination of a data driven expert systems and flow simulation. This would yield an unprecedented level of operational efficiency. The integration at enterprise level through portal will bring applied production optimization and intelligent field concept to reality. The ultimate objective is to empower operating company to improve real-time operation decision-making and production optimization.
Mudline Tubing Hanger Experience in Auger-Gulf of Mexico Wells
Authors: Stuckey Joe , Urban Larry , King James , Melancon Andy
Published: December 2007

This paper describes development and application of a new design mudline tubing hanger (MLTH) for suspending tubing weight below the mudline in offshore wells. The new design has been deployed in fifteen Auger wells with 100% success. A total of 1,005,000 lbs of tubing weight is currently isolated from the tension leg platform (TLP) using these devices. Though there were notable lessons learned throughout the deployment of the MLTH in the Auger development, there have been no failures of this equipment throughout the project.

The Shell deepwater Auger development in the Gulf of Mexico consists of six main reservoirs ranging in depth from 15,000 ft to 19,500 ft. The TLP lies in 2,860 ft of water, 137 miles off the Louisiana coast. (Figure 1, 2) The TLP was installed and development commenced in 1994, with the completion of the A-6 well. To date nineteen producers have been drilled in the field. On record days the field has produced 109,000 BO/day and 431 MMcf/day. Current production flows from 13 wells, including 6 subsea.

The Auger TLP has 32 subsea slots with twenty slots predrilled for wells. The TLP displaces 73,000 tons. Suspension of weight below the mudline permits more efficient use of buoyancy capacity. A device known generically as a Mudline Tubing Hanger (MLTH) is used to accomplish this by suspending tubing weight into the casing below the mudline. In July 1997, following experience on two Auger wells with another tubing hanger system, a new Mudline Tubing Hanger design was deployed for the first time on the A-20 well.
Project Portfolio Management – A Low Cost, High Return Business Solution
Authors: Davidson J. W. , Erdogan M. , Dowty T. , DiPaolo E. J. , Garrison C.
Published: December 2007

Portfolio management is an ill-defined and, often, overused term. According to CIO magazine1, "ask seven Chief Information Officer's what portfolio management is, and you'll get ten answers." Whether a company's portfolio solution entails consolidating data into a spreadsheet or employing modern portfolio theory to develop an efficient frontier, the goal is to ensure long-term business success by optimizing return at the minimum risk.

In a recent survey, CIO Magazine2 explored factors influencing long-term business success. Magazine editors interviewed executives from 100 companies identified by them as the most innovative in the world. Many executives contended that success depends on uncontrollable influences such as macroeconomics and pure dumb luck, never the less, chances for success can be maximized by leveraging tools and processes to anticipate and capitalize on macroeconomic factors.

A proof-of-concept case study describing a project portfolio management engagement with a Fortune 500 client is presented. Engagement objectives were to develop a business screening and portfolio planning solution that Minimizes reliance on luckProvides a holistic view of all investment opportunitiesConsistently quantifies riskLeverages modern portfolio theoryEnables cash flow and revenue forecastingDelivers the tools and processes for management to stabilize and grow revenue in a highly volatile market.

The business solution was applied to the client's 111 West Africa investment opportunities and entailed quantifying the risked value of investments, stochastically evaluating opportunities in a consistent manner, constraining the portfolio with investment thresholds, and portfolio optimization to balance risk and return.

The study demonstrates that project portfolio management can be a low-cost, high-return solution. Compared to the client's initial West Africa profit-to-investment portfolio (discounted P/I), the optimized case study portfolio (B) reduced Net Present Value (NPV) by 11% while eliminating 50% of the risk. Furthermore, opportunities were identified for immediate savings of $8 million dollars. The cost to develop and apply the solution was approximately $130,000.
Integration of Horizontal Wells In Reservoir Models: Input from an Outcrop Study
Authors: Lerat O. , Doligez B. , Desaubliaux G. , Daniel J. -M. , Eschard R. , Garcia F. , Chauvin H. , Coureaud B. , Nussbaumer C. , Rouvroy P.
Published: December 2007

The integration of horizontal well data in static reservoir models results in better reservoir characterization in terms of structural geometry, facies and fracture distribution, and the quantification of heterogeneities. This improved characterization may have an impact on the dynamic reservoir model, and hence on production performance. An outcrop study was carried out at the reservoir scale, in order to address the principal issues to be resolved when integrating horizontal well data in a reservoir geological model, with emphasis on two key points: 1/ the loss of well information after discretization to a fine grid and 2/ the impact of the uncertainties associated with the well trajectory on the reservoir modeling.

The chosen case study is the Upper Ismay interval of the Pennsylvanian Paradox Formation, whose depositional setting corresponded to a very shallow, mixed carbonate / siliciclastic platform. The geometry of the sedimentary bodies is roughly tabular at outcrop scale. Detailed sedimentological sections are described along the trajectory of several horizontal pseudo-wells logged on a continuous outcrop, with a horizontal length of around 200 meters. In this approach, the siliciclastic intervals, around 5 meters thick, are assumed to be reservoir targets. Shale breaks constitute internal heterogeneities and the carbonate layers are inter-reservoir barriers.

A detailed geological reservoir model has been built from the outcrop database using a geostatistical approach. The type and volume of the data lost after discretization has been evaluated for different sizes of grid mesh.

The influence of the uncertainties associated with the well location within the reservoir grid has been illustrated and quantified using several different trajectories described on the outcrop panel. For each pseudo-well included in the domain of uncertainty, geostatistical simulations have been performed and compared with a reference simulation, using the overall porous volume generated after simulation for quantification.

This approach leads to key recommendations for the integration of horizontal well data in subsurface reservoir studies.
Implementing Successful Mergers in the Oil and Gas Industry
Authors: Knabe Steven P.
Published: December 2007

Mergers and acquisitions have become major strategic levers for oil and gas companies to strengthen their technical and financial resource base and reduce cost structures. However, oil and gas companies have found that expected synergies from mergers are difficult to achieve: Merged organizations often operate in a cumbersome fashion, with poorly defined work processes and inadequate understanding of how the organization matrix should functionTechnical and administrative functions remain fragmented, resulting in limited information sharing and poor integration of functional expertise into operational decisions.

This paper examines how these and other merger-related issues can be addressed in planning and executing oil and gas company mergers.
Simulation of Lithologically Complex and Fracture-Dominated Monterey Production from the South Ellwood Reservoir
Authors: Zahedi A. , Abdassah D. , Ershaghi I. , Steve Horner
Published: December 2007

The Monterey Formation in the oilfields of California Offshore represents a unique flow system where the major fractures and faults serve as conduits and a system of microfractures supports these major channels. A rendering of the seismic and sub-seismic faults on a 3-D geological model was used to build a flow system representing this formation for the South Ellwood Field. On the basis of core data, outcrop information and other downhole surveys, the bulk matrix is believed to not contribute to either the flow or to the storativity. Through the application of the concepts presented in the paper, the case study of the South Ellwood field is reviewed in terms of the extraneous information that guided the selection of a realistic conceptual model for history matching purposes.

The uneven rise of oil water contacts in various faulted intervals and uneven gas liberation pockets characterized from fluid entry surveys, have served as effective information in conceptualizing and modeling the bottom aquifer influx and delineation of various non-communicating compartments. Comparison of this model with two other conventional fractured reservoir simulation models shows a better history match can be achieved with the proposed compartmentalized system.
A Streamtube Approach for Modeling Mass and Heat Migration for Thermal Recovery Methods
Authors: Usman Usman , Arihara Norio
Published: December 2007

This paper presents a new reservoir simulator for mass and heat migration based on the streamtube technique. The current version of the program focuses on characterizing migration of the injected fluid. The method is heavily based on the distribution of the pore volume along each streamtube calculated by using the Time-of-Flight method. This information and the 1D solution of mass and energy equations are used to determine thermal migration as well as temperature changes at production wells. The streamtubes are derived from an underlying velocity field, which is obtained from the solution of the pressure equation under the assumption of incompressibility. The compressibility effects are accounted for in the 1D solutions along periodically changing streamtubes.

Simulations are carried out for a five-spot well pattern in 2D areal domains with various types of heterogeneity under different injection scenarios. We confirmed that the results from the streamtube approach had a reasonable balance between its ability to provide an insight into the behavior of mass and heat flow and the computational efficiency. Comparisons with a commercially available simulator both validated the method and illustrated the cases in which this method is more useful to reservoir engineers.
Accurate and Effective Simulation for Reservoirs of Complex Geological Features
Authors: Sutopo Sutopo , Arihara Norio
Published: December 2007

Heterogeneous geological features, such as fractures, faults, shale laminae, and cross-stratified beds, can exert significant effects on the flow performance. Accurate simulation of these complexities requires two model functions, i.e. abilities to accurately compute both pressure and velocity and to efficiently handle permeability tensor. In this paper, a flux continuous model incorporating full tensor permeability was developed for two -phase flow of immiscible and incompressible fluids. Flow systems were split into two subsystems of configurations, one for elliptic equation of global pressure and the other for parabolic equation of saturation, and solve both sequentially by means of the mixed finite volume element (MFVE) method.

Numerical examples of simulating flow in sand-shale system and fractured reservoirs are presented to prove the effectiveness and robustness of the model demonstrating particular suitability for handling high heterogeneities and accurately resolving steep pressure gradients. The MFVE method can accurately calculate the flow variables, and generate more realistic streamlines than the standard finite difference method for a discontinuous permeability field. Applications to naturally fractured reservoirs validate the use of full-tensor effective permeability for accurate and effective simulation.
Weight Reduction of Off-Shore Natural Gas Liquids Processing Facilities
Authors: Westover J. , Hoadley A. , Dyson A. E. S.
Published: December 2007

The oil and gas producing and processing industry is unique in that many of its facilities are not land-based factories. The processing schemes are very similar to land based factories, but the need to build the factories in the water is unique. Structural engineering and construction engineering costs are much higher, simply because there is no soil to hold the complex up out of the water.

There have been several publications on different methods to reduce and manage weight of these facilities by optimizing the equipment or structural design. These include larger turbo-machinery (allowing one unit to perform the task of two), combining two valves into one body (allowing weight reduction where double block and bleed isolation is required) and the use of High Integrity Pressure Protection Systems (HIPPS). However, a literature review shows that there is very little work published on how process engineers systematically synthesize a process flow scheme with a view to weight reduction. Process integration offers one possible method to obtain weight reduction.

This paper examines some process integration issues and techniques in an effort to systematically reduce weight, using two case studies of different feed composition to support the findings. Three areas were investigated, ranging from very simple utility modifications to managing turbo-machinery exergy.

For the case where the feed gas had a relatively low condensate component (lean gas), minor utility modifications and aggressively managing energy transfer across the process and utility pinches reduced equipment list weight by 22%. For the rich gas example, the same methodologies reduced equipment list weight by 6.5%, with potential for further reduction up to 9.5%.

This paper is a summary of the work of Westover1.
Sand Mass Prediction in a North Sea Reservoir
Authors: Papamichos Euripides
Published: December 2007

An engineering analytical model for sand mass prediction is presented. The model is based on a sand production function with parameters correlated to the uniaxial compressive strength of the formation. The model is used for the prediction of sand production in an inclined perforated well in the North Sea.
Some Advances in Near Wellbore Geomechanics
Authors: McLennan John D. , Abou-Sayed Ahmed S.
Published: December 2007

There has been substantial recent progress in coupling geomechanical effects to reservoir response, thus dramatically improving representation of the consequences of rock response to pressure changes. New reserves have been identified from compaction. Injection geomechanics has gained an increase in interest due to its impact on the reservoir, faults and well hardware. Changes in transmissibility are now seriously implemented in reservoir engineering tools with more attention directed at the presence of compaction and dilatant bands around producers or injectors. Efforts are progressing to ensure adequate coupling between the local effects of the rock deformation near the wellbore, as well as along faults or bedding planes, and the evolving stresses and deformation in the reservoir.

This paper attempts to discuss current gaps in understanding the intricacies and details of coupling farfield deformation to well completion. Examples are shown where reservoir compaction or dilatancy is explicitly coupled to near-wellbore behavior, with specific application for assessing well performance and survivability. The analyses can use reservoir simulations coupled with analytical predictions of stresses and deformations in individual simulator blocks. The predicted stresses and deformations form the boundary conditions for finite element modeling that can focus in on the details around the completion itself. This is in contrast to the current approaches that use explicit coupling of pressure and deformation in complete massive finite element representations, with refined gridding around the completion.

The intimate details of coupling reservoir deformation to the completion require more intensive consideration. For example, "How can the cement sheath be represented?" or "What are some of the constitutive considerations in the near-wellbore region that impact integrity?" and "How is varying transmissibility related to well integrity?" These issues are considered. There are three goals: Start to recognize completion and production management practices that will improve completion longevity and optimize well productivity.Identify reasonable methodologies for representing the coupling between the completion and the reservoir, including yielded zones (dilatant and/or compactant), compaction bands with varying transmissibility, the cement sheath with or without a microannulus and the mud cake.Delineate approximate methods that will adequately forecast completion distress and permeability impairment without the necessity of expensive and time-consuming detailed finite element simulations.
Influence of Pore Pressure, Composition and Microstructure on the Acoustic Properties of Shales
Authors: Dewhurst David N. , Siggins Anthony F. , Raven Mark D.
Published: December 2007

The presence of smectitic shales can cause problems for drillers in the form of wellbore stability problems resulting from the presence of swelling clays and overpressures due to low permeability. Prediction of overpressures in such sediments is hampered by interlayer water in the mineral structure that is not accounted for in porosity determinations whether by wireline methods or laboratory drying techniques. This study looks at the composition and microstructural response to stress of acoustic properties of the Muderong Shale, a regional seal in the Carnarvon Basin on the Northwest Shelf of Australia. Physical properties and composition are intimately tied to the acoustic response of the Muderong Shale at both sonic and ultrasonic frequencies. Velocity variations from downhole shales in wells from the Carnarvon Basin can mainly be tied to smectite content but also to overpressure. The presence of smectite results in anomalously low velocities in the Mud-erong Shale and the development of both compaction fabrics and induced microfracture generation result in significant acoustic anisotropy. The high degree of anisotropy of the Muderong Shale at ambient pressure can be related to the presence of both a sedimentary compaction fabric and high aspect ratio compliant microfractures. Variations in velocity and elastic constants can be related to the microstructural response to imposed stresses. Determination of the relative contributions of these two causes of anisotropy in shales may provide a method by which to distinguish overpressure-generating mechanisms from acoustic data.
Use of the D3 Model for the Estimation of Forces Acting on a Cutter in Rock Cutting and Drilling
Authors: Dagrain F. , Tshibangu J. -P.
Published: December 2007

This paper reports applications of the D3 single cutter model developed by Dagrain (2001) [1,2] at University of Minnesota (UMN), based on the original phenomenological cutting model developed by Detournay and Defourny in 1992 [3].

This paper comes to present the continuity at the FPMs, of the researches performed at UMN. In the present paper, the D3 model has been used to model two different field cases studied in the past at the FPMs, in order to confirm the validity of the D3 model for simulating rock cutting with multi-cutters tools.

The model has also been applied to estimate the best parameters to use to optimize the cutting efficiency for both particular field cases. Finally some basic rules are given to design tools (drill bits or cutting chain) to minimize the specific energy and to maximize the rate of penetration. The model can also be used to estimate the power needed in rock cutting and drilling.
Hydrocarbon Liquid Phase Definition, Determination and Allocation in Two-Phase Hydrocarbon Reservoirs
Authors: Hamoodi A. N. , Babajan S. A. W. , Desouki A. H. , Ruffier-Meray V. , Pina A.
Published: December 2007

Identification of the produced hydrocarbon liquid stream, as either oil or condensate, in two-phase hydrocarbon reservoirs, gains special significance in cases where the gas cap and its associated condensate owners are different from the oil rim owners. Thus, the definition of the produced hydrocarbon liquid stream is critical in determining the allocation of the produced liquid phase and accounting for the volumes of oil and condensate produced to satisfy marketing constraints. In this paper we will discuss classification procedures of the produced hydrocarbon liquid stream, laboratory sampling and analysis, and compositional modeling demonstrated for a saturated oil reservoir with a large gas cap and a critical fluid reservoir.
Field Testing and Study of Horizontal Water Injectors in Increasing Ultimate Recovery from a Reservoir in Thamama Formation in a Peripheral Water Injection Scheme in a Giant Carbonate Reservoir, United Arab Emirates
Authors: Cunningham A. Bryce , Chaliha P. R.
Published: December 2007

Development trials of peripheral horizontal injectors were performed in an attempt to establish waterflood sweep within the low permeability lower half of a Thamama reservoir. This paper describes the performance of the horizontal injectors, as well as a time lapse formation tester interference test between a horizontal injector and open hole observation well, spaced 100 meter apart. The test was designed to measure the distance it takes water from the horizontal injector to break through into the high permeability upper half of the reservoir.

Interpretation of the results show that water from horizontal injectors moves vertically out of zone within 100 meters of the injection point, and is not contained within the lower half of the reservoir. Full field simulation after history matching the interference test results shows small increase in vertical and areal sweep efficiency resulting from utilization of horizontal injectors. Radioactive tracer injected into a horizontal injector in the lower part of the reservoir migrated upward into the upper part and traveled up dip 1km to an observation well within 3 years, traveling more than 3 feet per day.

While use of horizontal producers has been identified as the primary method for increasing recovery from the lower part of this Thamama reservoir, the benefits of horizontal injectors over vertical injectors is small. Horizontal injectors can only be justified when costs of adding a horizontal tail to a newly drilled injector is equally small. High recompletion costs of converting existing peripheral vertical injectors to horizontal injectors through sidetracking is not justifiable, or economic.
Fluid Characterisation for Gas Injection Study using Equilibrium Contact Mixing
Authors: Takahashi Koh , Fevang Øivind , Whitson Curtis H.
Published: December 2007

This paper describes the development of an equation of state (EOS) for a gas injection simulation study of a compositionally-grading near-critical oil reservoir. As the number of initial oil sample was limited and no gas-cap gas compositional data was available, the equilibrium contact mixing (ECM) test was used to (a) help tune the EOS to nearcritical phase equilibrium existing at the near-critical gas-oil contact, and (b) to estimate the initial gas-cap PVT properties. Available standard depletion type PVT data, multi-contact swelling test data, slim tube test data and ECM data were used in the development of the full-fluid "detailed" EOS using 16 components. Characterisation of the C7+ fraction together with regression of EOS parameters was carried out to tune the fluid model to match all available measured PVT data. Isothermal compositional gradient calculations were performed for all available samples and then a sample was selected to best represent the most important measured properties such as saturation pressure, saturated density and the compositional gradients in the reservoir. Equilibrium contact mixing data provide key gas-cap gas properties and vapour/liquid phase equilibria data for developing the EOS, also important for studying near-miscible gas injection processes.
Log-Derived Permeability in a Heterogeneous Carbonate Reservoir of Middle East, Abu Dhabi, Using Artificial Neural Network
Authors: Badarinadh V. , Suryanarayana K. , Youssef Fahd Zaki , Sahouh Khalid , Valle Antonio
Published: December 2007

Estimation of permeability in carbonates has been a challenge for many years. Well logs, particularly high-resolution logs, are influenced by rock properties. Therefore, when there is limited core coverage and scarce high-resolution log data, permeability estimation using the standard suite of logs (resistivity, density, neutron, caliper, gamma ray) is crucial for populating and constraining a 3D geological permeability model.

Two new traces, the deep and micro resistivity activity traces, are derived from the corresponding resistivity logs. The activity traces are not affected by fluid effects and, thus, preserve better the formation characteristics. Permeability estimation using an artificial neural network approach is made through a two-step process. In the first step, probabilities of log-derived rock types are estimated from a trained neural network using the micro and deep resistivity activity traces, and the standard suite of logs as input. In the second step, a separately trained neural network uses rock type probabilities from step 1, along with a suite of logs to predict permeability.

Two examples are provided to illustrate the validity of the method in predicting permeability in a heterogeneous carbonate reservoir located in Abu Dhabi, UAE. This reservoir exhibits permeability ranging from half a milli-Darcy to more than 20 Darcies. The first example represents a blind test where the estimated permeability shows good agreement with core permeability data. The second example demonstrates the predictive capability of the method in a non-cored well that is located in the vicinity of cored wells. The estimation technique is robust and was found valuable to supplement core data in the construction of geo-cellular permeability models.
Static and Dynamic Characterization of Fracture Pattern in the Upper Jurassic Reservoirs of an Offshore Abu Dhabi Field: From Well Data to Full Field Modeling
Authors: Gauthier B. D. M. , Auzias V. , Garcia M. , Chiapello E.
Published: December 2007

In the oil bearing reservoirs of a mature field in the offshore Abu Dhabi, the understanding of the fracture network is essential with growing gas and water productions. Fracture characterization and modeling at the full field scale is the key to match the production profile and to optimize infill drilling.

The interpretation of fracture data from image logs and cores allows defining accurately the fracture pattern in terms of orientation, typology, density and relation with lithology and faulting. Two main fracture sets are chronologically observed: (i) NW-SE fractures are generally mineralized and clustered around faults of similar orientations; (ii) NE-SW fractures are generally open, homogeneously distributed with their density controlled by the lithology and a few portion located in swarms.

The calibration of fracture data with PLT's in horizontal drains suggests that: (i) the main flow comes from the matrix in porous layers; (ii) in areas without mineralized fractures, wells can be connected to water, either through matrix (permeable layers) or through open NE-SW fractures, particularly in zones of large curvature where a higher fracture density is expected; (iii)in areas with mineralized fractures, water in permeable layers is channelized and tight layers can be vertically connected to more permeable layers by open fractures whereas the lateral flow can be hampered.

Full field fracture modeling is done through an innovative geostatistical approach. First, discriminant analysis is used to derive, from geological attributes that are known to be physically related to fracturing, a (geological) component best correlated to well fracture data. Second, sequential indicator simulation generates equiprobable fracture density maps. Third, optimization of infill drilling is made through risk analysis.

The pertinence of this approach for the optimization of well planning is validated against recently drilled wells. Matching the production profile is made more difficult however by the different opening times of production wells and by their complex completions.
"New Insights From Old Data": Identification of Rock Types and Permeability Prediction Within a Heterogeneous Carbonate Reservoir Using Diplog and Openhole Log Data
Authors: Aplin Graham F. , Dawans Jean-Michel L. , Sapru Ajay K.
Published: December 2007

Diplog and openhole log data has been used to predict reservoir rock type and permeability distribution within a heterogeneous Thamama Group reservoir from a field in the UAE. Porosities within the reservoir are fairly constant, but permeabilities vary by several orders of magnitude for a given porosity, reflecting variations in primary depositional facies and to a lesser extent diagenesis. The reservoir is characterised by common thin vuggy bioclastic-rich facies that form high permeability streaks and tight cemented intervals that are below the resolution of standard openhole logs. The higher resolution of the diplog tool allows the distribution of these thin units to be established.

The diplog data has been processed using the same techniques applied to modern image logs and a series of false colour pseudo-images generated. A diplog facies scheme was established based on the diplog pseudo-images, diplog microresistivity curve response, microresistivity curve activity, and openhole log response, which were calibrated using core. The diplog facies are grouped into a series of diplog rock types (DRT) based on their petrophysical properties and open hole log characteristics. These DRT can be directly related to core-based petrophysically defined reservoir rock types. Each DRT is assigned a permeability range based on statistical analysis of cored wells and then used to provide an estimate of permeability distribution and heterogeneity within uncored wells. Comparison of the diplog rock types with conventional core analysis and miniperm results from a series of ‘blind’ tests indicates that there is a good relationship between DRT and permeability, which shows a broad agreement with the detailed rock typing undertaken on core.

This study demonstrates the value of revisiting old data, and that where diplog data is calibrated with core data, meaningful geological interpretations can be made and provide a valuable input to reservoir characterisation in heterogeneous reservoirs.
Experimental Determination of Elastic Anisotropy and Biot's Constant in a Saudi Arabian Reservoir Sandstone
Authors: Azeemuddin M. , Khan K. , Khan M. N. , Abdulraheem A. , Rahim Minerals, Z. , Al-Qahtani M. Y.
Published: December 2007

Rock mechanical triaxial and hydrostatic tests were conducted on 1.5-inch diameter sandstone samples obtained from four wells. A total of 23 different depth intervals were tested, at pressures representing the in-situ reservoir conditions. Static elastic moduli (Young's modulus and Poisson's ratio) and static Biot's constant were determined from the results of the triaxial tests. Dynamic elastic constants of selected rock samples were determined from ultrasonic compressional and shear wave transmission data obtained under hydrostatic stress conditions through vertical, horizontal and 45-degree-oriented samples. Porosity and permeability measurements were also made on corresponding sister samples.

Wave velocities and the computed dynamic moduli indicated the existence of stress-induced elastic anisotropy, which was found to decrease with increasing confining pressure. Biot's constant values in planes parallel and perpendicular to the bedding were found to be nearly the same, indicating that the anisotropy in the wave velocities and dynamic elastic moduli does not translate directly into anisotropy in the Biot's constant. However, the Biot's constant in both planes decreased significantly with hydrostatic stress, indicating a stress-dependency.

The static Biot's constant obtained from triaxial tests also decreased with increase in axial stress, demonstrating a significant axial stress-dependency as well. The results were found to be in general agreement with the literature.
A Case History 3D OBC Seismic Data Acquisition Over a Giant Oil-Field Offshore Abu Dhabi
Authors: Lilley G. , Belaid K. , Hagiwara H. , Najia W. , Ebed A. , Usher L.
Published: December 2007

Fifteen hundred square kilometers of the 3D OBC Seismic Survey was acquired, over an 18-month period in 2000 and 2001, as a joint Venture between ADNOC, ADMA-OPCO and ZADCO. The seismic acquisition contractor was Petroleum Geo-Services (PGS).

This paper concentrates on some of the Operational, Quality & HSE aspects and the many challenges faced in acquiring such a highly specified orthogonal OBC survey (in excess of 300 fold) over a very active field which is extremely densely populated with infrastructure and partly located over very shallow water.

The field has hundreds of well head towers (jackets), huge super complexes, satellite platforms and many hundreds of kilometers of criss-crossing, untrenched oil, gas and water pipe-lines. Areas of dense coral pinnacles and other field debris exist. Water depths less than 5m were measured but even these depths were effectively reduced in many areas by the presence of the hazards.
Fault and Fracture Characterization Using 3D Interval Pressure Transient Tests
Authors: Zeybek M. , Kuchuk F. J. , Hafez H.
Published: December 2007

Permeability is one of the most important parameters that affects almost all phases of reservoir management and well performance. It is considered to be the most basic formation property and a tensor (directional dependence). As stated well by Weber1 in 1986: "Reservoir heterogeneity is among the major reasons why enhanced oil recovery is so difficult. Projects undertaken without detail reservoir evaluation often end in failures related to unexpected baffles to flow, permeability heterogeneity, or wrong appreciation of the residual oil distribution." Fractures and faults can behave as barriers, baffles, or open channels to fluid flow in the reservoir and often cause early water breakthrough, gas channeling, etc. that are costly.

In this paper, we use 3D interval pressure transient tests to estimate horizontal and vertical permeabilities and to delineate of fracture and fault conductivities. 3D interval pressure transient tests are conducted using the wireline conveyed dual-inflatable-packer module with multiple observation probes that can be set along the wellbore a number of times as the number of fracture and fault zones require. The dual-packer, with one meter open interval is set against the borehole wall to hydraulically isolate the tested section from the rest of the wellbore. In this set up, the dual-packer open interval encircles fractured and/or faulted zones. The formation fluid is produced through the isolated packer interval for more than a few hours, after which a pressure buildup test takes place. For the interval tests, the observation probes are usually mounted above and/or below the packer module. These probes measure pressure changes due production from the open interval at different locations in the formation.

For the interpretation of each interval test, first we use the well-known flow regime identification methods of pressure transient testing. After the flow regime identification and analysis, we use a computationally efficient optimization algorithm that allows simultaneous nonlinear parameter estimation of the unknown parameters (horizontal and vertical permeabilities and fracture and fault conductivities) from 3D transient pressure measurements that are spatially distributed. For this nonlinear estimation or history matching, a detailed reservoir model is constructed by incorporating to all geological and well openhole log data, particularly resistivity images that are crucial for identifying, testing, and modeling faults and fractures. During the minimization process, the reservoir model and its parameters are updated as all pressure measurements are matched with the model behavior. This process is continued until a satisfactory match is obtained for all 3D transient pressure tests.

Two examples (one synthetic and one actual field data) are presented to demonstrate the application of the methodology.
3-D Image Processing Techniques Applied to Carbonate Reservoirs and Structures
Authors: Massaferro Jose Luis , Bourne Ruth , Jauffred Jean Claude
Published: December 2007

Conventional 3-D seismic mapping is not an ideal predictive method when attempting to characterise carbonate reservoirs due mainly to the complexity and heterogeneity of carbonate systems. In carbonates, the combined effect of variations in depositional facies and diagenetic alterations plays a key role in controlling variations in sonic velocities and thus in acoustic impedance. As seismic facies are delineated by acoustic impedance contrasts, the depositional facies may be rather poorly defined for various carbonates environments (e.g. shallow-water platform carbonates). Accurate 3-D imaging of seismic facies and geometries is critical to construct a realistic, seismically constrained reservoir model 3D image-processing techniques of stacked and migrated data incorporate all three dimensions, which when combined help to identify/highlight events of significance in the data. The result is an attribute cube or volume that can be analysed and interpreted more objectively by the interpreter than the conventional horizon-based interpretation. We have applied various 3-D image-processing techniques to produce filtered seismic reflectivity data and volume attributes to better visualise and delineate seismic facies, geometries and the structure of heterogeneous carbonate reservoirs. Image filtering techniques were applied to improve signal-to-noise ratios and to suppress random noise to obtain a better reflection definition. Combined volume dip and azimuth was calculated from the seismic cubes to detect subtle stratigraphic features such as low-angle progradation units and shoal-type mounded seismic facies in the Permian Khuff and Upper Cretaceous Natih E reservoirs. Semblance volumes were used to highlight reflection terminations and helped to distinguish between stratigraphic and structural features. Texture mapping was applied to 3-D attribute-generated volumes to extract different seismic facies and properties, which can be related to potential good reservoir zones in the Malampaya field. 3D visualisation tools were used to image both horizons and faults of a complex inverted structure of a deep Upper Cretaceous lacustrine carbonate reservoir in the Yacoraite Fm. Argentina. Seismic facies and geometries interpreted from the attribute analyses, combined with interpretation of the original seismic and core/log data, allowed us to construct robust structural and depositional models of carbonate environments that were used as input for static reservoir models.
3D Visualisation for Seismic Processing
Authors: Ellis David
Published: December 2007

Seismic data can now be interpreted in great detail. Interpreters employ highly sophisticated systems that facilitate visualisation and interaction with 3D datasets. In contrast processors do not routinely analyse seismic data using the same tools as the interpreter. This is an unhealthy state of affairs – processors may be unaware of features in the data that are significant in terms of exploration or development; interpreters may identify problems in datasets that were invisible to processors.

3D visualisation and interpretation technology offers the opportunity to make a step change to key tasks performed in seismic data processing, for example first-break picking and velocity analysis. Potentially processors could benefit from the same orders of magnitude increase in productivity and attention to detail as interpreters have enjoyed over the last two decades.
Reservoir Management of a Giant Lower Burgan Reservoir in North Kuwait – Reservoir Monitoring and Production Enhancement by Innovative Tracking of Bypassed Oil and Time-Lapsed Data Integration
Authors: Chetri Hom B. , Khan Ali Nasar , Al-Ajmi Moudi F. , Srivastava Sanjeev , Al-Anzi Ealian , Al-Hajeri Mubarak
Published: December 2007

Lower Burgan reservoir is a giant multi layered reservoir in Sabiriyah field of North Kuwait operating under active bottom water drive as well as edge water drive. The reservoir is on production since 1960s and has so far produced about 63% of the original reserves. The effective reservoir management by innovative tracking of water movement, identifying segments with bypassed oil, opportunistic well workovers, prudent selection of infill well targets and continuous reservoir monitoring have made it possible to sustain the reservoir production rate near to the projected plateau and carry it forward for next 4-5 years.

The lower Burgan reservoir comprises predominantly channelised facies, which impact a high degree of heterogeneity to the reservoir. The massive M sand produces through a vertical sweep of aquifer whereas the interbedded L sand experiences largely lateral edge water sweep. The key of the reservoir/production management from this reservoir has been to monitor the water encroachment pattern and track the bypassed oil. The primary tool for tracking water movement & bypassed oil has been thermal neutron decay logs (Schlumberger TDT and Western Atlas PDK logs). These logs have provided excellent data for mapping water movement in lower burgan reservoir due to the high formation salinities and generally high porosities. The data was holistically analyzed in conjunction with time lapsed PLT and well test data. The information on identification of pressure regimes and vertical connectivity available from RFT data from recent penetrations added further confidence to the interpreted results.

A prudent strategy to acquire static bottom hole pressure measurements and PBU tests was developed so as to have the layer wise characterization and optimize the perforation planning. The event based well tests in key wells periodically led to deliverability optimization. The fluid characterization for each flow unit helped to refine the assessment of well performance vis-à-vis the completion. Innovative approach to estimate the sweep/ recovery efficiency and residual oil saturation by analytical methods proved useful to fine-tune the ranges of expectations.

Simulation models were made in 1980s and mid 1995 which are under revision at present. The model is likely to help the field engineers to manage this giant reservoir more effectively and efficiently on long term basis.