bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pressure Behavior of Horizontal Wells in Dual-Porosity, Dual-Permeability Naturally Fractured Reservoirs
Authors: Lu Jing , Zhu Tao , Tiab Djebbar 
Published: March 2009

Abstract
This paper presents pressure bahavior of horizontal wells in dual-porosity, dual-permeability naturally fractured reservoirs. The proposed equation is obtained by double Fourier transformation and Laplace transformation. The results calculated for combinations of various dimensionless characterizing parameters, including the permeability ratio between matrix and fracture systems, have revealed the unique behavior of naturally fractured reservoirs when the flow state within the matrix blocks is taken into account. It is concluded that, for the flow within matrix blocks will weaken the essential nature of fluid flow through a dual-porosity, single permeability medium revealed by Warren-Root model. This paper also presents the application of "Tiab's Direct Synthesis" to horizontal wells in an infinite acting dual-porosity, dual-permeability naturally fractured reservoirs with pseudo-steady state interporosity flow.
Steady-State Productivity Equations for a Multiple-Wells System in Sector Fault Reservoirs and Channel Reservoirs
Authors: Lu Jing , Zhu Tao , Tiab Djebbar 
Published: March 2009

Abstract
Currently in the oil industry, pseudo-steady state productivity equations for a multiple wells system are used in all reservoir systems, regardless of the outer boundary conditions. However, if the reservoir is under edge water drive or with infinite lateral extension, pseudo-steady state is no longer applicable. When producing time is sufficiently long, productivity equations based on the steady state are required.
This paper presents steady-state productivity equations for a multiple-wells system in homogeneous, anisotropic sector fault reservoirs and channel reservoirs. Taking fully penetrating vertical wells as uniform line sinks, and solving a square matrix of dimension n, where n is the number of wells, simple, reasonably accurate multiple-wells system productivity equations are obtained. The proposed equations which relate the production rate vector to the pressure drawdown vector provide a fast analytical tool to evaluate the performance of multiple wells, which are located arbitrarily in a sector fault reservoir or a channel reservoir. This paper also gives an equation for calculating skin factors of each well.
It is concluded that, for a given number of wells, well pattern, anisotropic permeabilities, skin factor, pressure difference between reservoir outer boundary and flowing bottomhole pressure, have significant effects on single well productivity and total productivity of the multiple-wells system. In a sector fault reservoir, the production rates are increasing functions of the sector angle; in a channel reservoir, the production rates are increasing functions of the reservoir width.
Use of Exclusion Zones in Mapping and Modeling Fracture Corridors
Authors: Ozkaya Sait I. 
Published: March 2009

Abstract
Fracture corridors are sub-vertical tabular fracture clusters which are associated with faults, or originate as incipient faults. Fluid conductive fracture corridors may have significant permeability and profoundly affect reservoir flow dynamics.
Mapping fracture corridors requires (i) locating fracture corridors and assigning to them (ii) length, (iii) orientation and (iv) fluid conductivity. Estimation of orientation and especially length is a major challenge in fracture corridor modelling. Exclusion zones may aid both in locating fracture corridors and assigning orientation and length. An exclusion zone is an area which can not have a conductive fault or fracture corridor passing through.
Exclusion zones around vertical wells are defined mainly by well tests and remaining oil column thickness. Borehole image logs, wells tests, lost circulation and openhole logs define exclusion zones in horizontal wells. A vertical well test with homogeneous matrix can not have a fluid conductive fault / fracture corridors within the circle of investigation. Oil column thickness can be estimated from a combination production logs, water cut history or from recent openhole or surveillance logs. Wells with thick remaining oil column and no water sweep can not have a nearby fluid conductive fault or fracture corridor. Horizontal wells with image logs or openhole logs showing no conductive fault/fracture corridor indicate an exclusion zone around the well where no faults or fracture corridors can pass through.
Improvement of Geologic Exploration Efficiency in Mature Oil and Gas Provinces
Authors: Khisamov R. S. , Bazarevskaya V. G. 
Published: March 2009

Abstract
Approaches and methods for oil and gas exploration have improved significantly with maturing of major oilfields.
At the initial stage of geologic exploration in Tatarstan prospects were identified by single coverage reflection profiling and structural drilling. The accuracy of these methods sufficed to identify large anticlinal closures. Efficiency of geologic drilling to evaluate the potential of deep intervals was rather high at that time, 88%.
In 1980-ies Tatarstan witnessed a wide-scale development and application of 2D seismic methods to search for small oil habitats, structural and lithologically-screened structural pools. The discovery ratio of prospects identified with 2D seismics in Tatarstan in 1980-ies reached 72–95%, in the Volga-Ural oil and gas province 12–89%, in Russia–20%.
At the initial and medium stages of exploration of zones with proved oil and gas potential primary objectives are structures with areal extent not less than 5 sq. km and closure at least 15 m. At mature stage of exploration (Republic of Tatarstan) primary targets are features with areal extent 0.5–1.0 sq. km and 5–10 m closure. Complicated geologic and economic environment attributed to exploration of deep carbonate pools, complex trapping mechanism, small-size and small-closure anomalies necessitated improvement of geologic prospecting methods.
Nowadays Tatneft Company successfully uses the technology of forecasting of local hydrocarbon accumulations based on a package of 2D and 3D seismic prospecting and non-conventional exploration methods, the major advantage of which is low costs.
So, lately in its exploration activity both on Tatarstan territory and in its license areas, Tatneft Company has been widely using advanced methods of geologic prospecting including investigation of seismic prospects with the help of neural network (NEUROSEISM system), geophysical and gas geochemical exploration methods, electromagmetic (EM) sounding, low-frequency seismic sounding, geochemical survey (Gore Sorber), and a number of others.
The Key Challenges for Optimization of a Tight Gas Field Developments Using a Multidomain Integrated Process: Application in a Mature and Emerging Environments (North America and Middle East)
Authors: Aly Ahmed , Ramsey Lee 
Published: March 2009

Abstract
As gas demand rises and operators turn to tight gas reservoirs for new supplies, the need to optimize the capacity and recovery potential from this type of reservoir has risen.
In this environment, a multidomain integrated process enables the data and activities of multiple domains to be integrated for single-well completion optimization and field geocellular and simulation modeling. Through this process, various development scenarios for completions and drilling locations can be systematically and rigorously analyzed.
Case studies from North America and the Middle East show applications of this process in two different environments, one mature and one emerging. The case from North America illustrates a use of the proposed process in a high-volume field development and the value of applying new technology to optimize the process until it reaches a "SMART"-factory-like workflow. With our new process, new technology can be integrated with adaptive modification to the factory mode. This approach will identify the development process that will result in the highest recoveries while maximizing the net present value from the asset. Alternatively, the case from the Middle East shows the application in a gas-condensate, tight gas reservoir in an emerging area. The challenge in this case is in collecting adequate necessary data early enough to plan for optimal development. Our case shows the value of collecting the key data early in a complex, tight gas environment and how early collection can impact the development later and avert costly decisions. Also, the special nature and cost of mobilization and limited equipment introduce a need for more stringent early collection of data (e.g., formation evaluation, core, fluid, geomechanics, etc.) that impacts our development before we start the project. This project illustrates the challenges of the developments in a new environment where the services and technology have not matured to the North America levels.
A key conclusion of the paper is that applying the field management process in both environments (North America and the Middle East) has resulted in significant improvements in production optimization, as well as in single-well and field development planning.
Rock Typeand Permeability Prediction of a Heterogeneous Carbonate Reservoir Using Artificial Neural Networks Based on Flow Zone Index Approach
Authors: Kharrat Riyaz , Mahdavi Ramin , Bagherpour Mohammad Hashem , Hejri Shahab 
Published: March 2009

Abstract
The Cretaceous carbonates of Sarvak formation formed large hydrocarbon reservoirs in the South-west region of Iran. The studied field is a tight carbonate reservoir in which several exploration wells have been drilled, and is in the process of development. Since, only few wells have core data, therefore it was decided to integrate the available core and log data using new methods that describe the carbonates heterogeneity more precise.
3D modeling of permeability is an essential part of building robust dynamic model for proper reservoir management and making reliable predictions. A good definition of reservoir rock types (RRT) could relate somehow better geological modes to dynamic models. Rock typing by flow-zone-index (FZI) and rock-quality-index (RQI) values proved to be an effective technique to develop porosity-permeability transforms for RRTs in a reservoir model.
RRTs were defined based on the core derived FZI through some mathematical and statistical approaches. Permeability estimation using artificial neural network approach (ANN) was then made through a two-step process. In the first step, FZI log was estimated from a trained neural network using the standard suite of logs as input (Gamma ray, Sonic, Density, Neutron porosity) and FZI-core as output in a subset of cored wells (Key wells). In the second step, individual trained neural networks implemented porosity-log and FZI-log from the first step to predict permeability-log for each RRT.
Validation of the predictive capability of the method in two cored wells (Blind-test wells) that are located in the field proved the estimation technique to be robust and was found to be valuable to supplement core data in the prediction of log-permeability in the entire reservoir wells.
For the sake of comparison between the result of this work and the work which was based on the integration of sedimentological, petrographical, and diagenetic study, the results were found to be in good agreement for most of the log interval. However, the predictions of the ANN approach in the regions where core data are not available are better and it follows the log property variation logically.
Unstructured Coarse Grid Generation for Reservoir Flow Simulation Using Background Grid Approach
Authors: Yadecuri M. Evazi , Mahani H. 
Published: March 2009

Abstract
Reservoir flow simulation involves subdivision of the physical domain into a number of gridblocks. This is best accomplished with optimized grid point density and minimized number of gridblocks especially for coarse grid generation from a fine grid geological model.
In any coarse grid generation, proper distribution of grid points, which form basis of numerical gridblocks, is a challenging task. We show that this can be effectively achieved by generating a background grid that stores grid point spacing parameter.
Spacing (L) can be described by Poisson's equation (∇2L = G) where the local density of grid points is controlled by a variable source term (G). This source term can be based on different grid point density indicators such as permeability variations, fluid velocity or their combination e.g. vorticity, where they can be extracted from reference fine grid. Once background grid is generated, advancing front triangulation and then Delaunay tessellation are invoked to form the final (coarse) gridblocks. This algorithm is quite flexible, allowing choice of the gridding indicator and thus providing the possibility of comparing the grids generated with different indicators and selecting the best.
In this paper, the capabilities of approach in generation of unstructured coarse grids from fine geological models are illustrated using a highly heterogeneous test case. Flexibility of algorithm to gridding indicator is demonstrated using vorticity, permeability variation and velocity. Quality of the coarse grids is evaluated by comparing their two-phase flow simulation results to those of fine grid and uniform coarse grid. Results demonstrate the robustness and attractiveness of approach, as well as relative quality/performance of grids generated by using different indicators.
Steamflood Piloting the Wafra Field Eocene Reservoir in the Partitioned Neutral Zone, Between Saudi Arabia and Kuwait
Authors: Barge David , Al-Yami Falah , Uphold Don , Zahedi Alireza , Deemer Art , Carreras Patricia E. 
Published: March 2009

Abstract
The concept of steamflooding the Wafra Eocene dolomite reservoir originated in various studies conducted in the 1980's. In 1999, a comprehensive EOR study and Eocene huff-n-puff pilot suggested that steamflooding could be a viable recovery process for the reservoir. As a result of these studies, a staged development approach was incorporated to test the viability of pattern steamflooding the Eocene reservoir. The objective was to assess key technical challenges associated with steamflooding an anhydrite and gypsum rich carbonate reservoir. Additional challenges were the lack of fresh water available for steam generation, high concentrations of hydrogen sulfide gas, and higher reservoir pressures compared to most active steamfloods. The staged approach called for a single pattern steamflood test followed by a larger multi-pattern pilot. As a result of this strategy, a single pattern steamflood test was implemented in 2006.
The design and initial performance of the small scale test (SST) single pattern steamflood pilot in the Wafra 1st Eocene reservoir are described in this paper. The pilot is comprised of one, 1.25 acre inverted five-spot pattern, consisting of four producing wells, a single injector and a single observation well. Continuous steam injection began in February 2006 at a rate of approximately 500 barrels per day cold water equivalent, 600 psig and a temperature of 489 ºF.
The primary goals of the single pattern test were to test application of a mechanical seeded slurry evaporator to process produced water for steam generation and to assess steam injectivity into dolomite reservoirs containing gypsum and/or anhydrite. Injectivity assessment included evaluating reservoir response to steamflooding and investigating the variation over time due to rock/fluid interactions. Secondary objectives included analyzing well productivity and evaluating well testing equipment, facilities, and well construction. The SST has a comprehensive data collection and surveillance plan to support evaluation of these goals and objectives. The surveillance plan includes the collection of pre-flood and post-flood core data, frequent well testing for rates and fluid compositions, daily temperature recordings and periodic logging.
After two years of operation, primary goals have been tested and exceeded expectations. A continuous thermal zone was developed in the 1st Eocene reservoir and steam breakthrough occurred at several of the producers. Generator feed quality water was produced at maximum throughput rate of 1,200 bwpd via mechanical seeded slurry evaporator equipment. Secondary objectives are currently being assessed with focus on current challenges of corrosion and scaling of producing wells.
Challenges of Producing Middle East Oilfields During the Maturation Stage—A Paradigm Shift
Authors: Mahroos Faisal Al , Zubari Hisham 
Published: March 2009

Abstract
The Middle East oil fields provide an important energy source for the world. They hold two-third of the world oil reserves (Figure: 1, Table: 1), provide one-third of the world's oil supplies and have the highest Reserves to Production ratio in the world of 821. Even though most of the Middle East oilfields are still prolific, many are already approaching the end of their primary stages as evident by increasing trends in water and gas productions. This is a natural process caused by maturation whereby a depleting oil reservoir looses its energy which results in oil productivity decline associated with intrusion of aquifer water and gas cap gas, when present. The challenge would be to transform the operation from Primary production to Secondary and Tertiary. This not only requires a change in the operation, but also a paradigm shift in reservoir management style and approach. This requires the identification of the pertinent issues and challenges that need to be resolved early and subsequently setting a roadmap plan to investigate, experiment and devise solutions. It also requires a quick, efficient and effective decision making process supported by modern corporate management style.
In this paper we attempt to document the Primary to Secondary and Tertiary transition experience based on the 77 years old Maturing Bahrain Field which was the first oil discovery in the southern part of the Arabian Gulf. The paper does not discuss in detail the decision making process and the corporate management styles of mature field operation.
Prediction of Wellbore Stability Using 3D Finite Element Model in a Shallow Unconsolidated Heavy-Oil Sand in a Kuwait Field
Authors: Ahmed K. , Khan K. , Mohamad-Hussein M. A. 
Published: March 2009

Abstract
As a part of field development campaign to produce heavy-oil from a shallow sandstone reservoir, among vertical wells, drilling of horizontal wells was considered as an option. However, due to the weak and unconsolidated nature of the reservoir sand, the stability of horizontal wellbore during drilling was considered a major unknown. The stability of rock around the wellbore during drilling is function of several factors including rock strength, in situ stresses, pore pressure and drilling parameters. Integration of a wide variety of data into a geomechanical analysis is required for wellbore stability predictions.
A comprehensive geomechanical study of the unconsolidated sandstone reservoir was conducted by incorporating data from six vertical offset wells in order to constrain the contemporary state of stress and rock strength profiles as a function of depth. The aim of the study was to evaluate the risk of hole stability during drilling, recommend a mud weight for drilling upcoming horizontal wells and to suggest azimuths along which horizontal wellbores will be more stable during drilling and production.
To closely simulate the actual stress state and rock deformation around the wellbore during drilling, a 3D Finite Element-based wellbore model was built. The analysis was performed for a range of mud weights to analyze the sensitivity of wellbore stability to mud weight variations. Based on the study, a mud weight was recommended to drill the planned horizontal wells. In addition, the analysis implied that for the observed stress state in the study field, horizontal wells oriented sub-parallel to the minimum horizontal in situ stress would be more stable during drilling and production compared to those oriented sub-parallel to the maximum horizontal in situ stress.
Potential Applications of CO2-EOR in the Middle East
Authors: Algharaib Meshal 
Published: March 2009

Abstract
Anthropological CO2 emissions to the atmosphere are identified as a major driver for the global warming effect. Major CO2 emissions sources are located within power and industrial sectors where fossil fuels are consumed to generate energy. With the anticipated escalation of global energy demand, CO2 emissions are also expected to grow. Therefore, reducing CO2 emissions to atmosphere is a fatal issue worldwide. Capturing CO2 from emissions sources and injected into safe geological places for storage shows a practical mitigation strategy through CO2 Capture and Storage (CCS) practices. In CCS projects, several options are available for CO2 storage such as subsurface aquifers, coalbed bed methane formations, or depleted oil and gas reservoirs. Alternatively to these storage places, CO2 can be utilized to enhance oil production from mature oil reservoirs. Utilization of CO2 in enhanced oil recovery techniques (EOR) is a well known practice in oil industry. Therefore, synchronizing between the objectives of storing CO2 and enhancing oil production to meet global demand can be achieved through CO2-EOR projects.
The giant oil reservoirs in the Middle East represent potential places for CO2-EOR projects. In this paper, oil reservoirs located in the Middle East are selected to evaluate the potential of CO2-EOR projects in the region. These reservoirs were subjected to CO2-EOR screening where the fluid and rock properties are compared with a well known criteria. Furthermore, an analytical model is used to predict the performance of CO2-EOR in these reservoirs. The results showed that implementing CO2-EOR practices would enhance the oil recovery while storing a considerable amount of CO2 in these reservoirs
Field Experiences Detailing Acrolein (2-propenal) Treatment of a Produced Water Injection System in the Sultanate of Oman
Authors: Horaska D. D. , Penkala J. E. , Reed C. A. , Law M. D. , Gaffney S. H. , Srour M. M. , Al-Harthy Abdulla Salim 
Published: March 2009

Abstract
Acrolein represents a unique chemical approach to resolving water quality and injectivity problems resulting from bacteria and sulfides in secondary recovery systems. The key to this approach is three-fold: Acrolein is a potent microbiocide; it scavenges hydrogen sulfide (H2S); and it dissolves iron sulfide (FexSy). In the subject field trial, a 9-fold improvement in water quality and a 16% increase in injection water rates were achieved.
This paper presents the results of a 9 week field trial of acrolein that was conducted using a batch application protocol in a 9,000 m3/day produced water injection system in a Petroleum Development Oman (PDO) field in the Sultanate of Oman. The results indicated a 90% reduction in planktonic sulfate reducing bacteria and 72% reduction in planktonic general aerobic bacteria over the course of the trial. Concentrations of dissolved H2S were lowered by 50%, with a consequent downward trend in oil-free suspended solids (OFSS). The impact on injection water quality was significant, reflected by a 9-fold improvement in Barkman and Davidson slope test results. The average total water injected per day increased from 9,019m3 to 10,442m3 (16%) over the duration of the trial. These findings are discussed in the context of best practices for injection water system management.