bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Approach to Wireline Logging in Directional Wells and Difficult Logging Conditions
Authors: Boyes J. S. , Elkington P. A. S.
Published: December 2007

Conventional wireline logging has always faced the challenge of obtaining data in highly deviated wells, horizontal wells and those with bad hole conditions. Typical solutions included pumping down tools through open end drillpipe, drillpipe conveyed wireline logging, coiled tubing conveyed wireline logging or ultimately Logging-While-Drilling.These operations are time consuming and costly.

A new openhole memory logging system was introduced in 2000, initially as a more efficient alternate to pipe conveyed logging in such wells.Extensive field-testing of this system over the last few years has yielded a series of technical developments that has evolved into a low cost and unique formation evaluation logging system.This system combines memory logging with a novel deployment system that yields a cost effective approach to obtaining high quality formation evaluation data.Obtained post-drilling, the shuttle system conveys memory logging tools rapidly to TD inside the drillpipe as part of a wiper trip or check trip.

Logging tools used in this system are designed to be extremely short and small diameter (2.25").The system is battery powered and includes a wide variety of capabilities including quad-combo measurements and, in the near future, repeat formation pressure testing.Logging tools are conveyed to TD inside the drillpipe.Once at TD, an electro-mechanical pressure activated release mechanism moves the tool string from inside the drillpipe into the openhole.A landing collar and latch mechanism maintains a mechanical connection between the top of the tool string and the shuttle system that remains connected to the drillpipe.A pressure signaling system not only controls the tool release but also provides simple two-way communications - a key element in providing real-time QA in the memory repeat formation pressure tester operations.Examples will be shown where these systems have demonstrated to be cost effective.
Energy Conservation Through the Implementation of Cogeneration and Grid Interconnection
Authors: Dashash M. A. , Mahfoudhi R.
Published: December 2007

With increasing awareness of Energy Conservation and Environmental Protection, the Arab World is moving to further improve energy efficiency.

The equivalent of over 2.6 MM bbl is being daily burnt to fuel the thermal power plants that represent 92% of the total Arab power generation. This adds up to close to one billion barrels annually.

In this paper we will introduce two strategies with the objective to cut-off up to half of the current fuel consumption.

Firstly, by improving the thermal efficiency. It is proven now, that cogeneration technology is able to bring the efficiency from the current average of less than 25% to up to 80%.As an example we will present the case of Saudi Arabia experience of implementing cogeneration, in particular within its hydrocarbon facilities and Desalination Plants.

Secondly, by interconnecting the power networks of all adjacent Arab countries. At least 2 factors plead for this direction. On one hand, the 4-hour time zone difference from Eastern to Western Arab World makes it easy to exchange power during peak and low demand periods. On the other hand, this will help to reduce the reserve capacity and save on corresponding capital investment, fuel, and O&M expenses.

Reaching the mentioned objectives is not only a major contribution to Energy Conservation, but also leads intrinsically to higher Environmental Protection.
Uncertainty Estimation in Production Predictions Constrained by Production History and Time-Lapse Seismic in a GOM Oil Field
Authors: Litvak M. , Christie M. , Johnson D. , Colbert J. , Sambridge M.
Published: December 2007

Successful uncertainty quantification requires many reservoir models matching field production data and time lapse seismic. We have been able to automatically generate nearly 50 history matched models for a GOM oil field using the Neighbourhood Approximation stochastic sampling algorithm. This allows us to produce uncertainty forecasts for various production scenarios.

Geostatistical simulation constrained by well log, core, and seismic data is applied for building geological and reservoir models. The parameters of the geostatistical simulation (channel directions, channel dimensions, variagram parameters, etc.) are considered as uncertain parameters. Additionally, end points of relative permeability curves, dependencies of compressibility factors and permeability on effective stress, transmissibility multipliers across faults, and water aquifer size are varied in the history matching process.

A misfit function is selected to quantify history match of model results with field measurements of water cut, gas-oil ratio, and reservoir pressure in production wells in different moments of time. Trends and variances of the observation data are determined and incorporated in the objective function.

The position of the water-oil contact at the beginning of the field development and after three years of production is estimated from time lapse seismic. Differences in the water-oil contact positions determined from the reservoir simulation and time lapse seismic are quantified and incorporated in the objective function.

The reservoir model has been run nearly 2400 times in the history matching process. The Neighbourhood Algorithm is applied for the selection of the values of the history matching parameters in each run. The high quality of the history match is demonstrated,

An ensemble appraising procedure based on a Bayesian framework is used to determine probability distributions of the history matching parameters and to assign probabilities to the simulation models (runs). About 50 models with the highest probabilities (which cover 99% of the cumulative probability range) are selected for the predictions. A general tool has been developed for the definition of statistical parameters of production predictions (mean values, confidence interval, etc) and their changes in time. Uncertainty estimations for the base case predictions and several production scenarios are demonstrated.
Coalbed Methane Simulator Development for Improved Recovery of Coalbed Methane and CO2 Sequestration
Authors: Syahrial E.
Published: December 2007

Proposal

Sequestration of CO2 in deep unmined coal seams is currently under development for improved recovery of coalbed methane (ICBM) as well as permanent storage of CO2. Recent studies have shown that CO2 displaces methane by adsorbing more readily onto the coal matrix compared to other greenhouse gases, and could therefore contribute towards reducing global warming. In order to carry out a more accurate assessment of the potential of ICBM and CO2 sequestration, field based numerical simulations are required. Existing simulators for primary CBM (coalbed methane) recovery cannot be applied since the process of CO2 injection in partially desorbed coalbeds is highly complex and not fully understood. The principal challenges encountered in numerical modelling of ICBM/CO2 sequestration processes which need to be solved include: (1) two-phase flow, (2) multiple gas components, (3) impact of coal matrix swelling and shrinkage on permeability, and (4) mixed gas sorption.

This paper describes the development of a compositional simulator for improved recovery of coalbed methane and CO2 sequestration. The new features that describe the complex process of CO2 injection are implemented here. The numerical results for enhanced recovery indicate that matrix swelling associated with CO2 injection could results in more than an order of magnitude reduction in formation permeability around the injection well, hence prompt decline in well injectivity. The model prediction of the decline in well injectivity is consistent with the reported field observations in San Juan Basin USA. Also, a parametric study is conducted using this simulator to investigate the effects of coal properties on the enhancement of methane production efficiency based on published data.
Integrated Analysis of Down-hole Corrosion Logs to Investigate Casing Leaks
Authors: Al-Ghasham Y. Y. , Catte D. R. , Al-Haji A. A.
Published: December 2007

Despite the application of impressed current cathodic protection (ICCP), the Hawiyah and Haradh areas in the Ghawar field of Saudi Arabia have experienced external corrosion-related casing leaks through relatively shallow aquifers in a number of water injection wells.Many of the wells with failures were less than 10 years old and required costly workover repairs.

Down-hole corrosion logs were ran in these wells and others to investigate the cause(s) and mechanism(s) of the casing leaks.The logs were run under dynamic cathodic protection conditions to develop a better understanding of the problem and to enable the authors to determine cost-effective preventive measures to reduce future failures.

This paper presents a detailed analysis of the investigative corrosion logs, which include ultrasound, electromagnetic and potential measurement type logs. Findings will focus on cement quality, electrochemical interference between offset wells, and the effects of changing the magnitude of the applied cathodic protection current.
Sustainable Management of a Large Oil Field in Libya
Authors: Bremeier M. , Elashahab B. M. , Goh T.
Published: December 2007

This paper presents the efficient implementation of an integrated reservoir-management strategy with the example of a large oil field in the Sirte basin. The reservoir-management strategy targets a recovery factor in excess of 50% in line with high HSE standards such as gas utilization and produced salt water re-injection.

The immediate evaluation of key uncertainties, a focused data acquisition programme and proper data analysis enabled the early identification of optimisation potential. A tarmat at the initial oil-water contact was identified at a very early stage and detailed special core analysis led to the correct prediction of its threshold pressure. The encroachment of the bottom drive aquifer and the tilting dynamic oil-water contact was correctly forecasted by reservoir simulation. In conclusion, a substantial modification of the initial development plan was implemented.

A production optimisation strategy of ‘edge-to-top-displacement’ was selected. With a balance of off-take and pressure support, the recovery of down-dip wells was optimised in advance. The steering of the tilted secondary oil-water contact was monitored by reservoir surveillance, i.e. pressure and saturation monitoring. Reservoir simulation was again efficiently used and enabled the exact prediction of different recovery strategies. This also incorporated the management of water shut-off's in producing wells.

Artificial gas-lift was implemented to optimise recovery of wells with high water-cuts. Detailed interaction between different disciplines resulted in a modification of the standard API gas-lift design with considerable improvements.

The sustainable reservoir-management of the As Sarah oilfield is based on tailor-made data acquisition and state-of-the-art analysis and interpretation. With an integrated approach, including all relevant disciplines, it was possible to implement a custom-made development schedule resulting in a remarkable recovery factor.
Compact separation By Means of Inline Technology
Authors: Schook R. , van Asperen V.
Published: December 2007

In a conventional separator, with the exception of mist elimination, separation is usually achieved by allowing the fluids to have a few minutes retention time under the influence of gravity. Separation equipment can be reduced in size bythe application of a centrifugal force, which is many times gravity. The result of this is that centrifugal separators can be manufactured as a very compact unit. One step further is to fabricate the equipment according to pipeline design codes so as to avoid the complexities associated with the use of pressure vessels. Inline separators are based on cyclonic technology and can be regarded as mono-cyclones. At the moment two types of separators are available and qualified for the market. The first one is a Degasser where the aim is to separate gas from a liquid continuous flow. The second type is a Deliquidiser acting in the opposite way namely separating liquid from a continuous gas stream. Besides this, liquid/liquid inline separators are in development at the moment. Besides the compactness of these inline separators, the flexibility in terms of turndown, pressure drop and efficiency is a significant benefit compared to conventional separation equipment. The paper describes several types of newly developed inline separators and inline separator-systems. In addition current installations, namely those on Statoil Statfjord B and Sleipner T platform and on the BP ETAP platform, along with their specific benefits and cost savings are discussed. It will be shown that inline technology can and has played a major role in the de-bottlenecking and upgrading of existing top-side facilities. Besides this several sub-sea applications on new and existing oil and gas fields are currently being assessed for the application of this inline technology.
Optimizing Stimulation of Coalbed Methane Reservoirs Using an Integrated Fracture Modeling Approach
Authors: Valencia K. J. , Chen Z. , Hodge M. O. , Rahman S. S.
Published: December 2007

Conventional methodologies have failed to address the difficulties involved in the design and execution of fracture treatments of reservoirs with complex geology and stress conditions such as coal bed methane (CBM) reservoirs. This paper presents an innovative technique to optimize and design hydraulic fracture treatments in naturally fractured CBM reservoirs. This methodology integrates (1) a three dimensional (3D), finite element based numerical design tool to predict the fracture geometry for given reservoir and operating conditions, (2) a production model to estimate fluid flow in the CBM reservoir, and (3) cost analysis to optimize the design parameters against different field scenarios using a hybrid genetic-evolutionary optimization tool.

The technique has been used to design fracture treatments in a coal bed methane reservoir to illustrate its potential benefits in improving the reservoir's productivity. Results of this study have shown that the use of a 3D geometry model enabled realistic post-frac productivity analysis. This provided reliable conservative estimates on the revenue derived from the stimulation program. Furthermore, the optimization approach allowed operators to incorporate operating constraints based on sound industry practice and company guidelines for a cost-effective exploitation of CBM reservoirs.
Optimization and Scaling of Reservoir Models
Authors: Lenoach B. , Bowen G.
Published: December 2007

We report on an investigation into optimization techniques that could be useful for the automatic matching of production data. One key objective is to extract the maximum amount of information from the data. Our starting point is a series of grids of differing refinement starting at a coarse scale and an associated set of property parameterizations at increasing resolutions. Automatic optimization algorithms are investigated that utilize the differing scales. The aim is to develop optimization methods that can extract maximum information from the production data and are fast and robust enough for practical use.

The algorithms written for this study, which were initially developed for stand-alone single-phase flow models, have subsequently been implemented in a system using a standard commercial simulator. The results presented here are for synthetic models using a simulated truth case; the models are introduced in order of increasing levels of realism.
Three-Dimensional, Three-Phase Discrete-Fracture Reservoir Simulator Based on Control Volume Finite Element (CVFE) Formulation
Authors: Fu Y. , Yang Y. -K. , Deo M.
Published: December 2007

Proposal

A three-dimensional, three-phase black oil reservoir simulator has been developed using the Control Volume Finite Element (CVFE) formulation. Flux-based upstream weighting is necessary to ensure flux continuity and solution stability. Traditional CVFE formulations for reservoir simulation are not flux continuous. Flux continuity is observed with respect to all the phases; the solutions are locally and globally mass conservative. In addition, numerical aspects of the problem are not any more complicated than the finite- difference techniques, since numerical integration of dependent variables in the control volume is not required. It is thus established that CVFE formulation can be employed for field-wide reservoir simulation as an alternative to finite- difference formulations. Comparison of the results to results from a finite-difference simulator is presented.

The formulation is fully implicit. State-of-the-art parallel, linear solvers (coupling with the Portable Extensible Toolkit for Scientific Computation (PETSc)) are used. The simulator is appropriate for reservoirs of complex geometry. The formulation is applicable to anisotropic and heterogeneous domains, with full-tensor permeability. Fractures and faults are represented by lines (in two dimensions) and planes (in three dimensions). The difficult task of generating an unstructured mesh for complex domains with faults and fractures is accomplished in this study. Results of two-phase and three-phase simulations in a variety of fractured/faulted and nonfractured domains are presented. These domains are geometrically complex and are not easily represented by traditional finite-difference discretization. Fundamental aspects of fracture flow mechanics, such as imbibition, water bypassing, etc. are more easily examined using these simulators. Capillary pressure functions in matrix and fractures are very important in determining recovery behavior. Different combinations of capillary pressures in matrix and fractures can be examined with these models. The models were implemented in parallel on a 18-processor Linux cluster (64-bit Opteron chips) using Message Passing Interface (MPI). Speedup of up to 12 on a 16-processor setup was observed.
Dual-Mesh Simulation of Reservoir Heterogeneity in Single-and Dual-Porosity Problems
Authors: Atan S. , Al-Matrook M. , Kazemi H. , Ozkan E. , Gardner M.
Published: December 2007

This paper presents dual-mesh computing in simulation of reservoir heterogeneities in single- and dual-porosity reservoirs. The dual-mesh approach provides a great tool for computing displacement processes and saturation distribution on the same fine-grid as the underlying geological models and is also extremely powerful in simulation of naturally fractured, dual-porosity reservoirs. This approach may even be used for the fine-scale computations in compositional modeling of petroleum reservoirs. In principle, the dual-mesh computing surpasses the benefits of streamline simulation both in single and dual-porosity problems. Several convincing examples are presented to illustrate the broad applications. The reasons for the accuracy and efficacy of the dual-meash computing are also explained.
Simulating Residual Oil Saturation in Miscible Gas Flooding Using Alpha-Factors
Authors: Barker J. W. , Prévost M. , Pitrat E.
Published: December 2007

A method for imposing residual oil saturation in compositional simulation of miscible gas injection processes is proposed. It is based on use of alpha-factors found by a simple analytic calculation.

The method is validated on a one-dimensional model, then applied to full field simulations of miscible gas injection in the Deep Jusepin reservoir in Venezuela. In this case, the alpha-factor approach was judged to have been successful, improving the physical representation of the process and probably making the simulation results more realistic.

Finally, the method is compared with other possible approaches, principally (a) excluding a specified amount of oil from the flash calculations, or (b) using a dual porosity model.
Precambrian Field Oman from Greenfield to EOR
Authors: Al-Riyamy Q. , Kelly S. , Al-Rawahi A. , Matsuura T. , Davis D. , Henning R. , Terres R.
Published: December 2007

A group (the Cluster) of nine intra-salt Precambrian age reservoirs is located in the south of Oman 70 km from the nearest infrastructure and has been identified for potential development. Four reservoirs are currently producing via depletion. Although primary depletion provides a robust and economic development, Petroleum Development Oman (PDO) intends to implement a development based on EOR miscible gasflood at the earliest opportunity. If successful, a miscible gas injection project has the potential to triple the ultimate recovery compared to primary depletion. In order to demonstrate the technical feasibility and economic viability of a miscible gasflood, one of the identified Precambrian reservoirs (Field A) was extensively modelled both statically and dynamically.

A complete subsurface reservoir characterization was underpinned with an extensive data acquisition program, including: new 3D seismic acquisition and processing, full-reservoir section coring and sedimentologic facies description, routine and special core analyses, standard wireline logging, bore-hole image logs and interpretation, well test data (stimulation and cleanup, stabilized flow test, pressure buildup, MPLT, and standard and miscible PVT analyses) and interference pressure testing (from permanent down-hole pressure gauges).

Integrated static and dynamic compositional modelling of the field identified the primary subsurface uncertainties as: compartmentalization, permeability heterogeneity and injectant gas composition (to achieve miscibility). Pressure interference results indicate that faults locally act as baffles (not barriers) and that no field wide thief zone is present. Miscible PVT experiments show that an average Cluster gas should be multiple contact miscible at pressures below original reservoir pressure.

A comprehensive suite of geological static model realizations and compositional dynamic simulations were generated to capture the spread in reservoir heterogeneity, STOIIP and ultimate recovery. Gasflood recovery factors from these full field simulations varied from 25% to 55% and demonstrated that a miscible gasflood in this reservoir is attractive even in the pessimistic case. Field A will be the first miscible gasflood in the Cluster. Based on the studies approval have been given to develop the field with miscible gasflood
An Adaptive Multiphase Multiscale Finite Volume Simulator for Heterogeneous Reservoirs
Authors: Tchelepi H. A. , Jenny P. , Lee S. H. , Wolfsteiner C.
Published: December 2007

We developed an adaptive reservoir simulator for accurate modeling of multiphase flow and transport in large scale heterogeneous reservoirs. The simulator is based on a multiscale finite volume (MSFV) method. We describe both IMPES and sequential implicit formulations. The algorithms are sensitive to the specific characteristics of flow (i.e., pressure and total velocity) and transport (i.e., saturation). To obtain the fine scale (i.e., fine grid) flow field, two sets of basis functions - dual and primal - are constructed. The dual basis functions, which are associated with the dual coarse grid, are used to calculate the coarse scale transmissibilities. The fine scale pressure field is computed from the coarse grid pressure via superposition of the dual basis functions. Having a locally conservative fine scale velocity field is essential for accurate solution of the saturation equations (i.e., transport). The primal basis functions, which are associated with the primal coarse grid, are constructed for that purpose. The dual basis functions serve as boundary conditions to the primal basis functions. To resolve the fine scale flow field in and around wells, a special well basis function is devised. As with the other basis functions, we ensure that the support for the well basis is local.

Our MSFV simulator is designed for adaptive computation of both flow and transport in the course of a simulation run. Adaptive computation of the flow field is based on the time change of the total mobility field and triggers selective updates of basis functions. The key to achieving scalable (efficient for large problems) adaptive computation of flow and transport is the use of high fidelity basis functions with local support. We demonstrate the robustness and computational efficiency of the MSFV simulator using a variety of large heterogeneous reservoir models, including the SPE 10 comparative solution problem.
Finite Volume Methods for Coupled Stress/Fluid Flow in a Commercial Reservoir Simulator
Authors: Shaw G. , Stone T.
Published: December 2007

The flow equations in commercial reservoir simulators are generally discretized using the finite difference method, whereas for stress equations it is more common to use the finite element approach. In a reservoir simulator designed to include geomechanical effects, these two distinct types of equations must be solved with some degree of coupling. It is therefore natural to ask whether suitable finite volume methods can be derived for the stress equations - so that the stress and fluid flow models can share a common derivation, and what are the relative merits of finite volume and finite element methods for these coupled systems.

In this paper we present a finite volume discretization of the stress equations as implemented in a commercial reservoir simulator with an option to couple the stress with the fluid flow. We demonstrate that the method is locally conservative and retains second order accuracy on general threedimensional grids. We discuss the imposition of various types of boundary condition and describe the implementation of special features such as faults, pinch-outs and local grid refinements. We also present a comparison with other approaches based on finite differences1,2 and finite elements3. The relative accuracy, efficiency and robustness of these three different approaches are discussed.

Finally the paper presents some case studies demonstrating the suitability of the finite volume approach for realistic geomechanical simulations.
Water Management in North ‘Ain Dar, Saudi Arabia
Authors: Alhuthali A. H. , Al-Awami H. H. , Soremi A. , Al-Towailib A. I.
Published: December 2007

This paper presents a study on a six-year water management strategy in North ‘Ain Dar to reduce water production, prolong well life and enhance oil recovery. This field has been under peripheral injection for more than thirty years. Three strategies were implemented during the past five years to achieve optimal water management: 1) production optimization, 2) rigless water shutoff jobs, and 3) horizontal drilling. The success of these strategies can be attributed to a full understanding of the drive mechanisms that control fluid transport in the reservoir. This paper presents these mechanisms and their impact on water management strategies. The effectiveness of these strategies have been evaluated and supported by field data.

Horizontal drilling and rigless water shut-off proved to be effective techniques to control water production and enhance recovery in this gravity dominated system. Since 1999, production optimization has also played a significant role in controlling the water production and maintaining a constant water cut.
Effective Integration of Reservoir Heterogeneities, Fracture Networks and Fault Communication and Their Challenges in Bahrain Field Simulation Models
Authors: Kumar K. , Abdulwahab A. E. , AL-Muftah A.
Published: December 2007

The Bahrain field is an asymmetric anticline trending in the North-South direction. The field was discovered in 1932. The field is a multi-stack carbonate and sandstone reservoirs most of them oil bearing. The fluids range from tarry oil in Aruma zone to dry gas in the Khuff zones. The geology of the field is extremely complex with a large number of faults especially in the Wasia group formations, which contain the major oil reservoirs of the Bahrain field. These reservoirs are at different stages of the production cycle. Following a 3-D seismic acquisition campaign in the year 2000, Bapco took up an integrated study to develop numerical models as the main tool to assess alternative production mechanisms. This integrated study faced a significant number of challenges, which had to be overcome with innovative ideas.

The challenges included representing communication between reservoirs through faults, complex rock and fluid distribution from heavy oil to condensate, gas injection, aquifer encroachment and fracture intensity. Although the hardware required for handling the large simulation models was meticulously selected based on benchmark data of the various machines, the geological complexities posed serious problems while running the simulation models.

This paper describes the effective integration of the reservoir heterogeneities, fracture networks and fault communication in the simulation models built for different zones of Bahrain field. It also highlights the challenges faced during history matching process and the approaches adopted to overcome these challenges.
An Integrated Approach for Assessment of Water Holdup in a Multilayer Carbonate Reservoir
Authors: Abdelmawla A. , Dabbouk C. , Urasaki D. , Ateeq B. , Kutty A. R.
Published: December 2007

This paper gives a Field case history of a giant multilayer carbonate reservoir located offshore Abu Dhabi. This reservoir has field-wide lower permeability Stylolite layers between the main producing zones. Interestingly, some water hold up phenomena has been observed above Stylolite layers which gives doubt on the degree of vertical communication between the different reservoir producing zones (Fig. 1). This phenomenon can be related to the negative capillary forces in the oil wet reservoir rock and/or the vertical permeability across the Stylolite layers.

An integrated approach is given for the evaluation of water hold up by investigating both the vertical transmissibility across the Stylolite layers throughout the reservoir and the capillary forces due to oil wetting characteristics of the carbonate rock. The results of different methods for evaluation of the vertical permeability (Kv) will be given. These methods include: laboratory results from whole core vertical permeability (Kv) measurements at reservoir conditions using brine, multi-well vertical interference tests (VIT), single well VIT across the stylolite layers combined with MDT/RFT data, specially designed tracer injection tests in dual injector/producer well, and estimations from transient well test data for horizontal wells. Laboratory measurements of capillary pressure at reservoir conditions will also be shown explaining its role in water hold up.

The results from a simulation sector model study will be presented for assessment of vertical communication through Stylolite layers by integrating different sources of data. This study quantifies the effect of Kv uncertainty on the expected field performance.
Case History of Cost Reduction Optimization Efforts in a Mature Field
Authors: Van Gisbergen S. , Kumar S. , Harris J. , Al-Barwani B. , Himawan E.
Published: December 2007

Application of technically sound well and reservoir management (WRM) principles together with cost reduction measures utilising the latest technologies are the key to maximising economic recovery from mature reservoirs. The fields are in one cluster in Petroleum Development Oman. More than 250 major well entries are executed each year. The main measures that are applied to improve production and reduce costs are: integrated reservoir surveillance plans, better sequencing of the workover units, muli-disciplinary input to workover proposals, ESP monitoring and the introduction of new technology such as one-rig-up coiled tubing for cleanout, saturation-logging, perforation & stimulation. Together these processes have reduced well intervention costs by 20% and increased net oil gains by 10%. This paper aims to demonstrate that the application of intensive WRM techniques and appropriate technologies can reduce the unit cost for well interventions.
Grid and Streamline Models: Comparative Study Related to the Production History of Fractured Carbonate Reservoir
Authors: Anissimov L. , Kilaykov V. , Chizhov S.
Published: December 2007

The Upper Devonian carbonate reservoir characterization of the Pamyatno-Sasovskoe Oilfield, Volgograd Region, Russia, is based on geological data, geophysical log, hydrodynamic and tracer investigations. The reservoir model based on geostatistical techniques with grid blocks has been used to update a flow simulation to available data on production history. The reliability of this reservoir model is lower because of the match to available data is unacceptable. The method to model permeability on the coarse scale presents the combination of the borehole radon indication and tracer investigation. According to tracing results, a streamline-based model is to be most realistic, gives a basis to propose the parameters and properties of streamlines and to predict the water-cut process.
Visualization Experiments on Immiscible Gas and Water Injection by Using 2D-Fractured Glass Micromodels
Authors: Shariatpanahi S. F. , Dastyari A. , Bashukooh B. , Haghighi M. , Sahimi M. , Ayatollahi S. S.
Published: December 2007

Two series of flow visualization experiments were carried out to examine the behaviour of immiscible gas injection and water flooding in two-dimensional porous micromodels with fractures at various orientations. One main objective of the study was to test the validity of several contradictory speculative theories that have been proposed in the past in order to explain oil recovery in fractured reservoirs, produced as the result of gas injection or water flooding. All tests were performed under water-wet condition at various injection rates of immiscible gas and water. Our experiments indicated that the average of the maximum oil recovery obtained by immiscible gas injection is about 60%, while it is about 75% by water flooding. The experiments also suggest that, the average oil recovery during gas injection is a strong function of the fracture orientation, whereas the recovery by water flooding is not very sensitive to fracture orientation.Gas injection at rates higher than the free-gravity drainage rate results in displacement fronts that are not stable. The instability is caused by viscous fingering (channelized transport) of the displacing gas through the oil.
Evaluation of Multiphase-Flow Correlations for Gas Wells Located Off the Trinidad Southeast Coast
Authors: Persad Shelley Lucy
Published: December 2007

Multiphase flow correlations are used to determine the pressure losses incurred as a result of fluid flow through pipe.This evaluation is necessary since energy is ultimately lost as a fluid moves through pipe.These losses are incurred due to frictional losses, acceleration and the effects of the fluid weight for vertical flow. The predicted vertical tubing pressure drop for twenty-three (23) gas wells, using fourteen (14) multiphase flow correlations, were compared to measured field data.The results were analyzed to determine suitability and accuracy for varying reservoir and fluid characteristics such as gas rate, condensate gas ratio (CGR), water gas ratio (WGR), tubing size, age and angle of inclination for three Trinidad southeast coast gas fields; Field A, Field B and Field C.These fields are owned and operated by bp Trinidad and Tobago LLC.A total of two hundred and eighty (280) well tests were used for the analysis and this amounted to 3920 data points.

The results obtained showed that none of the correlations used to predict the tubing pressure losses perfectly matched the measured field data.The percentage error (pressure) was calculated and together with other criteria, was used to recommend which of the correlations would be most appropriate for use in each of the three fields under specific conditions. The analysis conducted showed that the Gray correlation met all the specified criteria and is the recommended correlation to be used in all fields.

INTRODUCTION

Background

The calculation of the pressure drop in gas wells is important for cost effective design of well completions and production optimization.Since none of the predictive multiphase flow correlations accurately predicts the pressure drop for all fields inclusive, it is essential that the analysis for best fit be done on a field-by-field basis.This study summarizes the findings when these multiphase flow correlations were analyzed for three Trinidad southeast coast gas reservoirs.The parameters of the wells used in this study, in some instances, far surpasses the range of parameters used to develop the correlations and also in similar past studies.

The three fields are located approximately 40 miles off the south east coast of Trinidad.The fields are part of the Columbus basin and the reservoirs are comprised of sands, which were formed from the Orinoco Delta deposits.
Efficient Evaluation of a Fractured Reservoir in the Syria Kurrachine Dolomite—A Case Study
Authors: Maretic S. , Trgovec-Grief N. , Žirkovic M. , Kenawy A. , Hook P.
Published: December 2007

Efficiently identifying and evaluating the producibility of fractures after drilling through potential reservoirs remains a challenge to both the oilfield operator and explorationist.Timely identification of features crossing the drilled borehole, indication of feature permeability, and testing of the well at the most promising depths with the drilling rig still on location are the keys to cost-effective development of tight and fractured reservoirs.

The Kurrachine Dolomite formation in central Syria is of Middle Triassic age and has low primary porosity.Economical production from Kurrachine reservoirs is therefore highly dependent on the drilled wells encountering zones of permeable secondary porosity.

This paper presents a field example demonstrating the success of wireline-conveyed services in evaluating the producibility of the Kurrachine Dolomite. The services involve the latest technology sensors for petrophysical formation evaluation, electrical imaging of the borehole to evaluate the depths of electrically conductive features crossing the hole, acoustic measurements to evaluate the relative permeability of the conductive features, and testing of the depths of interest by sampling, pressure measurement, and real-time formation fluid analysis.Analysis is presented to show which wireline measurements are particularly important to the operator in this environment.The paper presents techniques successfully implemented to overcome the challenges in formation pressure evaluation and fluid sampling of the Kurrachine formation.

Because the formation is accurately evaluated in real time with the drilling rig on location, the combination of services permits efficient, cost-effective decision making for development of Kurrachine Dolomite reservoirs.
A New Production Logging Tool Allows a Superior Mapping of the Fluid Velocities and Holdups inside the Well Bore
Authors: Dandarawy H. , AlMutairi A. , Abdouche G. , Khedr O. , Elkadi A.
Published: December 2007

Drawing the flow profile of the three phases (oil, water and gas) downhole is the ultimate goal of production logging. However the flow regimes that develop inside the well bore can be very complex (e.g. stratification, mist, annular, recirculation, etc) and the mapping of the fluid velocities and holdups inside the well bore is key to the proper evaluation of the individual phases flowrates at every depth level along the survey interval.

The mapping ability of the present production logging tools is somewhat limited; consequently difficulties are encountered when interpreting data sets that were acquired in such complex downhole conditions at the present time.

Flow Scan Imager is a new tool which comprises five mini-spinners, six electrical and six optical probes that get deployed downhole once the tool is across the survey interval. Each mini-spinner will evaluate the localized fluid velocity that is passing by it, whilst each electrical and optical probe will respectively evaluate the localized water and gas holdup that prevail around its place. When deployed, these sensors will be positioned in such a way that their measurements will constitute a map of the fluid velocities and holdups along a vertical cross section of the well bore at every depth level thus enabling a superior estimation of the individual phases flow rates in complex flow regimes downhole.

The use of this tool in deviated and horizontal wells will undoubtedly enable the users to better understand their production regimes, to define a more accurate flow profiles and consequently plan more efficient remedial works or production strategies, which will inevitably improve their ultimate hydrocarbon recovery.
Designing Effective Sand Control Systems to Overcome Problems in Water Injection Wells
Authors: Sadrpanah H. , Allam R. , Acock A. , Norris M. , O’Rourke T. , Murray L. R. , Wood D. J.
Published: December 2007

This paper provides guidance for selecting and designing optimum sand control systems for water injector wells. This guidance is based on a detailed study on issues and problems in water injection wells in the Foinaven field operated by BP.

Given openhole, stand-alone screen failures experienced on two Foinaven water injector wells, a water-injector sandface-completion study was commissioned with the following objectives: to review the issues and problems in water injector wells, propose possible solutions, and conduct engineering designs for water-injector sandface completions listed below.

Cased and perforated Openhole stand-alone screens Openhole gravel packs Openhole frac packs Cased hole frac packs Expandable screens

The paper summarises possible causes of sand control failure in the Foinaven field water injection wells and provides potential mitigations by selecting solutions using conventional and innovative technology.
Determination of WAG Ratios and Slug Sizes Under Uncertainty in a Smart Wells Environment
Authors: Esmaiel T. E. H. , Fallah S. , van Kruijsdijk C. P. J. W.
Published: December 2007

Smart well technology (down-hole measurement and control) has progressed significantly over the last few years. Previous research has concentrated on the application of the technology to secondary recovery[1,2,6]. This study aims to advance the technical application to tertiary recovery concentrating on WAG processes. The primary operational problem cited in literature is early breakthrough in production wells. This makes it potentially a prime candidate for smart wells based on initial success with smart wells in mitigating early water breakthrough.

A 3-D 3-phase compositional reservoir simulation model with smart wells is implemented in a commercial reservoir simulator. The goal is optimization of the global sweep efficiency under economic constraints through the control of the injection size of each slug, and the controlled injection rate of each well segment along the wellbore under uncertain geological and fluid parameters.

The WAG process is sensitive to reservoir, fluid, and economic parameters which justifies the need to quantify the uncertainty in production and associated risk involved. Gradients are determined through perturbation of the forward simulation.The gradients provide optimal control settings for the injection and production settings of each well. This study demonstrates the feasibility of creating a response surface proxy model, using experimental design and analysis, to facilitate Monte Carlo simulation, uncertainty analysis and screening of performance forecasts.

The proxy model is several orders of magnitude faster than a simulation run allowing a statistical analysis of the uncertainty. Initial results on this model show significant improvements over an uncontrolled WAG production in optimizing the initial WAG and smart well production settings under uncertainty.
Reservoir Connectivity Analysis – Defining Reservoir Connections and Plumbing
Authors: Vrolijk P. , James B. , Myers R. , Maynard J. , Sumpter L. , Sweet M.
Published: December 2007

Gas, oil, and water fluids in channelized or faulted reservoirscan create complex reservoir plumbing relationships. Variable hydrocarbon contacts can develop when some, but not all, fluids are in pressure communication. Reservoir Connectivity Analyis (RCA) is a series of analyses and approaches to integrate structural, stratigraphic, and fluid pressure and composition data into permissible but non-unique scenarios offluid contacts and pressures. RCA provides the basis for fluid contact and pressure scenarios at all business stages, allowing the creation of fluid contact and segmentation scenarios earlier in an exploration or development setting, and the identification of by-passed pays or new exploration opportunities in aproduction setting. Combining conventional structural and fault juxtaposition spill concepts with a renewed appreciation of fluid breakover (contacts controlled by spill of pressure-driven, denser fluid, like water over a dam) and capillary leak (to define the ratio of gas and oil where capillary gas leak determines the GOC), we define permissible but non-unique scenarios of the full fluid fill/displacement/spill pathways of ahydrocarbon accumulation comprised of single or multiple reservoir intervals.

This new analytical approach has been used in a wide range of reservoirs, including clastic (from fluvial to shoreface to deepwater) and carbonate reservoirs, in fields around the world.RCA models have been used to predict fluid contacts in faulted reservoirs where other approaches failed, to locateby-passed pay opportunities for in fill drilling in mature fields,and to condition connections in reservoir simulation models. RCA is an integrated technology that challenges the interpreter to evaluate and incorporate fluid property, composition, and pressure data with stratigraphic and structural interpretations of a reservoir to achieve a deeper, more comprehensive understanding of reservoir compartments and the connections between them.
GTL Update
Authors: Apanel G.
Published: December 2007

Proven world natural gas reserves, which currently exceed 5,000 trillion cubic feet (TCF), have been growing at a faster rate than proven oil reserves. These gas reserves currently represent over 83% of the energy equivalence of proven oil reserves, of which about 75% is considered to be the less desirable heavy crude. In some remote locations, wellhead costs of natural gas have been estimated to be below $0.25/MMBtu, while the cost of reinjecting "associated" gas from crude oil production as an alternative to flaring may greatly exceed its value. About 3,000 TCF of such gas reserves is considered to be "stranded"; i.e., accessible by drilling but located too far from potential markets for economical transportation to those markets.

The chemical conversion of methane to liquid fuels and other higher value products or derivatives which may be more cost effective to transport long distances from remote gas sources has therefore attracted renewed interest. Even though Fischer-Tropsch (FT) synthesis is a technically proven gas-to-liquids (GTL) technology, the conversion of natural gas to liquid fuels such as diesel and gasoline as opposed to higher value chemical products such as chemical grade methanol has only relatively recently been perceived to be a potentially viable commercial proposition. Recent advances in FT synthesis technologies, particularly with regard to natural gas reforming and catalytic partial oxidation, coupled with anticipated increased demand for "clean" diesel fuel appear to be enhancing the economic viability of this route to GTL.

The focus of this paper is the prospective economics of promising technologies for FT based GTL diesel production.The scope of this paper includes a brief discussion of potentially important new developments which could have a significant impact on GTL process economics.