bluuebunny/crossref_metadata_2025 huggingface dataset:
Effective Permeability vs. Drainage Radius, Correlation for the Turbidites Oil Reservoirs—Chicontepec Paleochannel
Authors: Gachuz-Muro Heron
Published: March 2009

Chicontepec is associated to a submarine fan system deposited under complex tectono-stratigraphic conditions. Typically, between 8 and 16 major reservoirs are present. These set of reservoirs is composed of channel complexes that are flanked by, and rest on, lobe sandstones that grade into distal fan and basin floor deposits, resulting in high heterogeneity. All the reservoirs have permeabilities of 0.1 to 10 mD and porosities of 5–15 %. Primary recovery by solution gas drive is less than 5 %. The oil density varies from 18 to 45 °API depending on his structural position.

An aggressive number of well tests were conducted to characterize the fields in Chicontepec. Theses include build up, fall off, drawdown and step rate tests. In recent years, the tests were analyzed to identify well and reservoir factors affecting productivity as well as to determine the effectiveness of well stimulation by fracturing. The typical models used to adjust the information were both vertical fracture and radial homogeneous models. The effective permeability, as determined for these tests and/or advanced decline analysis, ranges from 0.1 to 15 mD. The results seem to indicate that the partial closing of the fractures is caused during the early exploitation. Further analyses suggest that the reservoir rock quality (facies model) along the linear and/or bilinear flow periods having a link with good production rates.

This paper presents a relationship found between the effective permeability and the drainage radius. This relationship could be applied to turbidites oil reservoirs with low permeability and low porosity. In order to avoid the interference problems and to optimize new wells, we propose an optimal drainage radius obtained of well test data, pressure-production history and composition fluids.
Improved Waste Injection Monitoring and Modified Operational Procedures: The Keys to Prolong Well Storage Capacity
Authors: Ovalle A. , Ronderos J. , Benelkadi S. , Gumarov S. , Simmons S.
Published: March 2009

Waste generated during exploration, development, and production of oil and gas fields are required to be disposed in a responsible and environmentally friendly manner. Over the years, environmental regulations governing the disposal of such waste have tightened and each day regulatory agencies are demanding more stringent policies, especially for remote and environmentally sensitive areas. Waste Injection (WI) has been proven over the past decade to be the safest and most efficient technology for final disposal of waste materials such as produced water, drill cuttings, spent drilling and completion fluids, scale waste, NORM, produced sand, production and well cleanup waste. This cost-effective technology complies with the strict environmental guidelines, such as the ones governing zero-discharge environments. More regulatory agencies are gradually recognizing WI as a robust solution to safe and assured final disposal of waste generated in upstream and downstream sectors of the oil industry.

WI has evolved from a simple pumping operation, with lack of sub-surface understanding, to an assured process that has integrated the knowledge from all areas of the operation: engineering design, equipment and operational parameters, monitoring, and quality control-quality assurance. This continuous assessment guarantees a cyclic process that identifies potential risks at early stages, and allows proper management and mitigation to prolong the life and integrity of the operation.

This paper presents the unique and technically challenging injection monitoring and pressure interpretation experience attained in different WI projects worldwide, where the in-depth interpretation of fracture behavior helped as a risk-prevention tool with mitigation options applied to operational parameter well specifics.

The continuous monitoring of injection data and parameters assists in developing a well history and a prediction mechanism for well storage capacity, extending the life of the injector and maximizing efficiency for the development of the field.
Enhancing Decision Making in Critical Drilling Operations
Authors: Shokouhi Samad Valipour , Skalle Pål
Published: March 2009

Many critical tasks in oil operations require cognitive skills for safe and efficient drilling. Oil well drilling is a complex process which frequently is leading to operational problems. One problem is wellbore cleaning. If the root cause of the problem was known, the treatment of the problem could be made more focused and efficient. However, to determine the root cause is difficult in this coupled process. One solution to this challenge is to apply knowledge intensive case based reasoning (KiCBR) methodology. KiCBR is a recent approach to problem solving and decision making where a new problem is solved by finding a set of similar previously solved problems, called cases, and reusing them in the new problem situation.

This approach consists of two major parts: hierarchy of the concepts with different relation strength and case based reasoning. Concepts are abstracted to symbolic entities. Through the selected fields, data (real time logs, end of well plan and daily drilling reports, etc) are utilized to provide case data base. In this study, three main root causes were chosen; solids accumulation, problematic formation leading to future well cleaning and problematic formation causing well cleaning problems. This paper presents how to determine the root causes for poor hole cleaning episodes by means of the CBR (Case-Based Reasoning).

All the involved parameters in each case were stored in the data base. Whenever an unexpected episode is encountered, highly similar case from the data base will come out for decision making. Furthermore, each case has specific and general lessons for those who are in charge of the operations. The match results were good enough but it needs to be improved through indicators that will reveal main cause more precisely.
Two-Zone Commingled Production using Intelligent Well Completion Coupled with ESP through a Hydraulic Disconnect Tool
Authors: Ansah Joe , Quaimi Bander I. , Shehab Mahdi A. , Al-Ajmi Fahad A. , Bani Fahad A. , Jacob Suresh
Published: March 2009

A dual-reservoir completion using Intelligent Well system together with an electrical submersible pump (ESP) in a high-rate well was recently deployed in one of the large carbonate fields in Saudi Arabia. The well was equipped with ESP to provide artificial lift to pump the oil to a centralized processing facility that is far a way from the well through a 2-zone "Smart" well completion, which remotely controls fluid inflow from each of the two laterals. This completion enables commingled production from two reservoirs while balancing flow contribution from each reservoir and avoiding cross-flow from one reservoir into the other.

Commingled production from stacked reservoirs in the same field, or a single reservoir with multiple pay intervals, has many benefits during the development of a field – higher production rates per well, cost savings from reduction in the total number of development wells, flexibility in locating surface facilities as a result of minimal footprint, etc., Wide variation in reservoir properties, coupled with existence of natural fractures within an active waterflood environment in this case, prompted adoption of Intelligent Well technology to control fluid withdrawal and enhance waterflood front conformance. Additionally, there was a need to use proven conventional ESP system to lift the expected high production rates from the two prolific reservoirs.

The new completion uses a re-designed downhole hydraulic disconnect tool with an integral anchor assembly, instead of other systems that have been used in the industry in the past, to connect the upper completion incorporating the ESP system with the lower completion that incorporates the Intelligent Well completion. Thus, ESP workover can be performed without the need to retrieve the Intelligent Well completion. This integrated system has enabled the two producing reservoirs to be commingled successfully and has provided the flexibility to control inflow from each reservoir in the future as the flow regimes change.

This paper describes the equipment selection process, completion equipment, planning and deployment procedures of the Intelligent Well completion. Economic drivers for this robust completion as well as the reservoir management implications of successful deployment in this test case well and future expansion across the entire field are also discussed.
FDP-Revisions: Keeping Your FDP's Green in a Fit-For-Purpose Manner
Authors: Garimella Sai , Kloosterman Henk Jaap , Horstmann Dirk , Gheithy Ali
Published: March 2009

Petroleum Development Oman (PDO) is operating many technically complex and mature onshore oil fields in the Sultanate of Oman. Recently PDO has established a ring-fenced Study Centre to carry out Integrated Field Studies to maintain up-to-date Field Development Plans (FDP's). Generation of a robust updated FDP typically takes up to 18 months, and takes into account full subsurface uncertainty and development options analysis in order to arrive at the optimum development. When executing these FDPs, new subsurface data comes in, which often generates new insights in the field that need to be incorporated. This does not require always a full new FDP-study, but a focused revision of the existing FDP. A so-called ‘Hit-Squad’ team was established to deliver these quick & fit-for-purpose FDP-revisions.

In this paper, a case study is presented related to a mature clastic oil field in the Sultanate of Oman. The latest FDP, generated in 2004, proposed a peripheral waterflood, however, the expected pressure support was not observed in the crestal part of the field. This created an exposure in terms of expected oil recovery and jeopardised the remainder of the FDP-implementation. This paper describes how the ‘Hit Squad’ attacked the problem and delivered a fit-for-purpose FDP-revision to bring the remainder of the development back on track.

This involved upfront understanding of the key issues. It was recognised early on in the project that the static model definition was not the main cause of the waterflood underperformance. The core of the problem was the poorer than expected injectivity of the 2007 flank injectors, which in combination with the adverse mobility ratio and the relatively large injector/producer spacing caused the poor waterflood performance. In addition, existing infield injectors were rate constrained to avoid excessive induced fracturing and short circuiting of water. Therefore, the focus immediately was directed to the relevant work activities to screen and optimise an infill pattern flood.

The team produced within five months a revised development plan, now proceeding with an optimised pattern waterflood, with 40 well locations identified and picked, resulting in no loss of recovery or delay to the development. The first well was drilled within 2 months of study completion and came in as predicted (Depth, SHC, Pres, Qinj). The key success factors were the ring-fenced nature of the integrated team, as well as the seamless cooperation between Asset and Hit Squad Teams. The concept of the Hit Squad is generic and should find wider application in the industry.
Increasing Production and Injection in Multilateral Horizontal Wells in Naturally Fractured Carbonate Reservoirs by Rigless Intervention—A Case Study, Offshore, Qatar
Authors: Lisigurski O. , Ferdiana W. , Haro C. , Maili E.
Published: March 2009

Due to the complexity and cost of stimulating horizontal multilateral wells in an offshore environment, all aspects of this project type must be considered prior to project implementation. Utilizing all technical disciplines to understand the reservoir characteristics and select intervention candidates greatly influences the chance of success for any project.

During 2006–2008, 39 wells (19 producers, 17 water injectors and 3 gas injectors) were stimulated in the Shuaiba reservoir in Idd El Shargi North Dome Field, offshore Qatar, resulting in production increases as high as 50% and injection increases as high as 100% in some wells. The wells were stimulated by rigless coiled tubing. A new tool that allows coiled tubing to enter each lateral in multilateral wells was used for these projects. This successful acid stimulation workover program utilized the fundamentals of engineering, geology, geophysics, and petrophysics and applied them with field operations. The screening methods developed led to further workover activity and new drilling development with anticipated reserve and production increases.
Forecasting OPEC Crude Oil Supply
Authors: Al-Bisharah Mohammed , Al-Fattah Saud , Nashawi Ibrahim Sami , Malallah Adel
Published: March 2009

No one can underestimate the importance of crude oil in the modern world today. It is considered the key foundation of the world's first trillion-dollar industry and the principal item in the balance of payments and exchanges between nations. To truly appreciate the significance of this precious commodity, just imagine the day when all of the world's transportation systems and factories cease to function when the world has consumed its last drop of oil. This brings us to the main and crucial question: How long will oil last?

Crude oil is the lifeblood of the 12 member-nations of the Organization of Petroleum Exporting Countries (OPEC), which produces 40% of the world's oil supply and holds three-quarters of the proven reserves. Reaching oil production peak can be alarming to OPEC members, where oil revenue is the main feeding stream of the gross national product (GNP).

Many researchers, in the past decades, tried to find an answer to this crucial and critical question. Unfortunately, crude oil supply forecasting is a challenging endeavor.

This paper presents our forecast for the OPEC countries supply of crude oil to years beyond 2050. We applied the "multi-cyclic Hubbert" approach that accurately models the oil-production history of OPEC countries, which are virtually most of the world's crude oil supplier.

The analysis indicates that the OPEC ultimate oil recovery is about 1.137 trillion barrels. Of this amount, about 0.9117 trillion barrels remain to be produced by the end of 2080, where the peak is expected to be in 2025 at the production rate of 90 million barrels per day. OPEC has 77% of the world's remaining reserves. Furthermore, most OPEC countries will peak between 2020 and 2030, and they will remain the world main supplier of crude oil for the next 200 years.
Investigating the Mechanism of Thermally Induced Wettability Alteration
Authors: Roosta A. , Escrochi M. , Varzandeh F. , Khatibi J. , Ayatollahi Sh. , Schafiee M.
Published: March 2009

Wettability is known as the relative tendency of a fluid to wet a solid surface in the presence of another fluid that coexists in a system. Oil recovery efficiency of an oil-wet rock, mostly fractured carbonate formations, could be improved by the spontaneous imbibition of water if the rock wettability is changed. In this study, contact angle measurement was used to investigate the effects of aging time in crude oil as well as those of steam exposure on the wettability of calcite, mica, quartz, and glass surfaces.

The effects of rinsing the aged surfaces with different solvents on wettability were also studied to check the accuracy of the method and the contact angle measurements process utilized in this work. Different results of wettability alteration were observed when the mineral surfaces aged in the crude oil were exposed to steam. Quartz, calcite, and glass surfaces regained their original water wetness, while mica surfaces showed a tendency toward increased oil wet behavior. Among the tested minerals, calcite surfaces yielded the least wettability alteration when exposed to steam. Glass micro-models were also used to investigate the effect of steam and hot water injection on their wettability. Results of fluid distribution and residual oil saturation in micro-models showed that the wettability changed toward water-wet during steam and hot water injection.
Innovative Solution for Drilling Pre-Khuff Formations in Saudi Arabia Utilizing Turbodrill and Impregnated Bits
Authors: Carrillo Gabriel , Farid Usman , Albrecht Michael , Cook Perry , Feroze Nouman , Nevlud Kenneth
Published: March 2009

The abrasive Pre-Khuff sandstones combined with high downhole temperatures and the propensity for BHA and bit sticking present a uniquely hostile drilling environment. These limit run durations and the ability to optimize ROP with the use of conventional rotary assemblies, PDMs/conventional turbodrills and/or rotary steerable systems. Catastrophic damage or loss of drill strings, poor hole quality and logging problems are common even with the advancements in PDC bit technologies.

Of the systems listed above, historically, turbodrilling systems have best addressed the high temperatures and the abrasive nature of the Pre-Khuff formations and held the potential for drilling economics optimization but have been unsuccessful in addressing bit sticking challenges. The resultant development of best practices produced only marginal results because they require surface intervention and thus did not fully address sticking problems (in particular bit sticking).

The engineering challenge was to develop a downhole device that automatically engages and imparts sufficient drill string torque to maintain bit rotation. The turbodrill device disengages when conditions return to normal and returns the operation to high productivity drilling without surface intervention. The turbodrill device coupled with advancements in BHA design, stabilizer and jar placement along with formation characterization and drill bit technology, is the solution to bit sticking incidents.

Presented with this advancement in turbodrilling technology, the Operator/Service Company team has completed trials using this technology and presents data that supports the use and benefits of anti-sticking technologies. With this success, the team has regained focus on drilling optimization and reset the goal for single run-casing point to casing point.
Petroleum Development Oman's Experience in Using Near-Infra Red Absorption Based Water Cut Meters for Well Testing and Production Monitoring
Authors: Al-Hanashi Khalil , Al-Sibani Salim , Lievois John
Published: March 2009

Continuous and accurate water cut measurement is a challenging aspect in well testing and production monitoring in Petroleum Development Oman LLC (PDO). As PDO's fields are ageing and water cut is increasing, the need for more accurate water cut measurement is becoming essential. A field trial of different water cut measurement technologies was conducted in October 2004. As a result, near-infra red absorption measurement principle was found to be a promising technology. Therefore, the first near-infrared based water cut meter was first introduced in PDO in 2005

Today more than 300 units of the above mentioned water cut meter are installed in PDO. Different applications and installations of the same water cut meter across PDO are discussed in this paper. These applications include well testing, gathering and production stations production monitoring and monitoring water in oil from test separator oil leg outlet. This paper highlights the pros and cons of each of the applications where the near-infra red absorption based water cut meter is used in PDO operations. To get more accurate well test in high water cut wells, PDO deployed the same water cut meters together with Coriolis flow meters for well testing in the highest oil producer field in PDO, with high water cut (above 90% on average). This paper presents PDO's experience as an end user.

Although using near-infra red absorption based water cut meters is relatively new in the oil and gas industry, it shows a promising potential for better water cut measurement accuracy. Caution must be given to the surrounding conditions that can affect the performance of the meter, specifically the homogeneity of the flow. Configuration and proper setting of the water cut meter is an essential first step for accurate water cut measurement
Sabiriyah Upper Burgan Geological Model and Reservoir Characterization
Authors: Al-Aziz Sabry A. , Al-Rowyeh Anwar , AL-Enezi Talal , Chetri H. B. , AL-Anzi Ealian
Published: March 2009

Sabiriyah field is located on North Kuwait area and was discovered on 1956 and producing from multi reservoirs. The upper Burgan is a multi billion bbl reservoir in NK, with very high degree of reservoir heterogeneity and extremely complex due to combination of discontinuous channel and shore face sandstone.

The objective is to make a detailed stratighraphic correlation, build 3D static model to evaluate reservoir units, maps individual sand bodes within each unit, management and development the reservoir. Also would help on a major program of water injection plan.

The SAUB reservoir 150 feet thick (early late Albian age) is classified into 6 depositional facies, 7 main reservoir unit and 20 flow unit based on integrated all data available via open hole logs, computed logs, seismic structure depth map of top reservoir, sedimentology studies, RFT and cores data. The correlation scheme has been created based on the identical of field wide correlatable surfaces which were picked from cored wells and interpreted easily on well logs and applied thru the entire field. Twenty one markers have been traced a cross the field, gross maps honoring the depositional trends have been prepared and used with top reservoir structure depth to generate the structure depth for each marker. Net sand maps were generated & carefully edited to reflect the conceptual model and used as an areal guide for deterministic distribution of property models as well as facies model. The high resolution model is achieved by generating 3 D faulted grid and integrating all the components such as all the structures, deterministic maps and petrophysical results in to one geocellular model.

The SAUB model presents a very successful case for the integration of different disciplines and considered a milestone for the recent activities in such heterogeneity reservoir in Kuwait.
Improving Oil Recovery in Heterogeneous Carbonate Reservoir By Optimizing Peripheral Water Injection through Application of Innovative Techniques
Authors: Chaudhry M. A. , Mahmeed A. A. , Wani M. R. , Mubarak H. A. , Thakur R. K. , Al-Rashidi H. R.
Published: March 2009

Excellent benefits in terms of oil recovery and economic returns can be achieved in heterogeneous carbonate reservoirs by optimizing water flood through continuous application of innovative techniques in reservoir management. The fact is illustrated in this paper by sharing the challenges and success of Kuwait Gulf Oil Company (KGOC) and Saudi Arabian Chevron (SAC), in the Wafra Oil field, located in the divided zone between Kuwait and Saudi Arabia. Peripheral water injection was initiated for Wafra-Ratawi reservoir in 1998 after extensive studies. The project provided excellent results in the first 5 years in terms of increased production rate, reduced GOR, managed water cut and improving ultimate recovery. The project faced major challenges, such as early water breakthrough in the first row of producers, development of low pressure pockets and increased GOR during the 6th year of its life.

The paper presents an overview of the innovative technology and principles of reservoir management utilized at each stage of project to maximize asset value to all stake holders of the joint venture. Five topics are covered. First, the challenges faced and the solutions implemented during the early phase of water injection. Second, it covers the application of available technology at proper time. Third, it documents the modifications employed in the water flood strategy utilizing bottom water injection through horizontal wells and sidetracking the existing producers and optimizing injection profile with integrated reservoir models, dump flooding in low pressure areas. Fourth, synergy approach to reservoir management has been discussed, and finally, the future potential and way forward is outlined. Application of the innovative technology at proper time has resulted in significant increase in production rate, ultimate oil recovery and asset value.

Sharing the Best Practices and lessons learnt while implementing the reservoir management strategy can benefit the industry in recovering more oil.
Medium Radius Horizontal Sidetrack Reduces Time, Cost and Risks in Deep HT Gas Wells
Authors: Simpson Michael A. , Al-Hamid Abdul , Faraj Yusri , Khalil Mohamed , Duran Roberto , Miller Clayton L. , Al-Khamees Shaker , Stewart Jeffry
Published: March 2009

Saudi Aramco's first medium radius horizontal sidetrack gas well, Haradh-AX1, was drilled and completed in June, 2008 in a record time of 48.7 days with 4,989 ft of reservoir contact and a 33% reduction in overall cost.

The previous, Khuff-C Horizontal sidetracks which included the same operations; de-completion, sidetracking and re-completion, averaged 83 days with 3,441 ft of sidetracked lateral across the Khuff-C.

Directional drilling in the medium radius lateral after building at 12°/100 ft to a sail inclination of 88° was characterized by better bit performance, lower torque and drag, improved wellbore stability and steerability.

In the previously employed long radius horizontal sidetrack design, extensive milling operations were required to gain access to the 8-3/8 in. open hole to sidetrack. The 8-3/8 in. long radius build section would then be drilled from the Base Jilh Dolomite, across the troublesome and sometimes abnormally pressured Lower Jilh and Sudair Shale formations to the top of the Khuff-C where a new 7 in. liner would be run and cemented. The 5-7/8 in. lateral would then be drilled across the Khuff-C and an open-hole completion run.

In the medium radius design, the sidetrack (ST) could be made deeper, in the same pressure regime, by cutting a ST window in the existing 7 in. liner 450 ft true vertical depth (tvd) above the Khuff-C target reservoir, kicking off and drilling 5-7/8 in. hole across the Khuff-C to total depth (TD).

This paper further details the time and cost savings possible from the application of proven medium radius drilling technology from Saudi Aramco's Arab-D Horizontal Oil wells produced from 6,500 ft tvd to the deep gas wells produced from the Khuff formation at 12,000 ft tvd, a new drilling environment.

More medium radius horizontal sidetracks are planned and a similar medium radius Khuff-B Horizontal ST, ANDR-AX1, which built at 32°/100 ft, was just successfully completed at 14,819 ft with a 2,400 ft horizontal section.
Successful Mitigation of Deepwater Shallow Flows in the East Mediterranean Region—Case Histories
Authors: Lopez Jesse , Garrett Don , Zanaty Akram , Waheed Arshad
Published: March 2009

In 2008 deepwater drilling marked a decade of operation in the Nile Delta region of the East Mediterranean Sea. The operating water depths ranged from 200 m to ultra deepwaters greater than 2600 m. The Nile Delta region has been no exception to the challenges of shallow gas and water-flow hazards observed in many of the deepwater projects of the world (Furlow 1998; Alberty 1998). An obvious consequence of an unexpected, shallow-fluid flow is an uncontrolled blowout situation with no drilling control equipment in place. In some reported cases, even after the flow was controlled before running casing, fluid flow occurred after cementing the surface pipe. Incidentally, this phenomenon is not only limited to deepwater operations in Egypt; similar blowout situations can be observed anywhere in the offshore Nile Delta.

This paper reviews two recent examples of shallow flows that occurred in the surface holes of two different wells. Each operation cost the operator between 1.5 and 4 million dollars to address the problem. Alternatively, several examples are also provided that illustrate how understanding the flow mechanism, predicting its occurrence, taking necessary precautions while drilling, and designing cement slurries suitable for deepwater cementing have resolved the issue. Proper well preparation, correct mud design, and foamed cementing have been effective solutions. Additionally, advances made in cementing designs for deepwater situations with low margins between pore pressure and fracture gradient, cool seabed temperatures, and unpredictable shallow flows, each working adversely on the slurry design, are discussed to help deliver safe and competent wellbores.
Analysis of Deposition Mechanism of Mineral Scales Precipitating in the Sandface and Production Strings of Gas-Condensate Wells
Authors: Franco C. A. , Solares J. R. , Al-Marri H. M. , Mukhles A. E. , Ramadhan N. H. , Saihati A. H.
Published: March 2009

Thick deposits of various types of mineral scales are presently forming in the tubulars and formation of gas producers drilled in Saudi Arabian carbonate reservoirs. These mineral scales precipitate when ideal thermodynamic conditions and dissolved minerals present in formation waters combine. Without remedial action over time, these deposits can grow thicker and end up plugging tubulars and the reservoir.

Thick deposits of mineral scales have recently begun to appear in gas producers in certain areas of the field. A comprehensive study was conducted to ascertain the nature of the precipitation mechanism and identify potential solutions to the problem. This paper details how laboratory analysis data, well production history, reservoir geology and petrophysics, and reservoir description were analyzed and used with sophisticated computer software to identify the formation damage mechanism and the different scale types precipitating in the wellbore and formation. Extensive simulation work was conducted as part of the study to forecast the type and amount of mineral scale precipitation that can be anticipated at varying reservoir and producing conditions. The study also evaluated the most cost effective and feasible ways to remove different types of scale deposits.

The future scale inhibition and removal strategies to be implemented in existing and future gas producers are being derived in large part from the results of the study described in this paper.
Characterization of Complex Carbonate Heavy Oil Reservoir—A Case Study
Authors: Iqbal Afzal , Smith John , Zahedi Ali Reza , Arthur Deemer , Al-Yami Falah M. , Meddaugh W. Scott , Rampurawala Mansoor A. , Li Bingjian , Gok Ihsan , Al Enazi Talal
Published: March 2009

The Paleocene/Eocene age 1st Eocene Reservoir is the shallowest producing interval of Wafra Field in the Partitioned Neutral Zone (PNZ), Saudi Arabia and Kuwait. Characterization of this heavy oil reservoir is challenging due to observed variations in oil viscosity, heterogeneity related to complex mineralogy, a possible dual porosity system, and the presence of fractures at varying scales. This case study of the 1st Eocene reservoir characterization in the steam flood pilot area will improve our understanding of the range and distribution of formation properties which is critical for management of the current pilot project.

This study presents several aspects of an integrated approach to characterize the 1st Eocene reservoir. The approach includes the quantification and distribution of the evaporite minerals and porosity, analysis of a possible dual porosity system, and evaluation of permeability using a new porosity partitioning technique. Data used in this study includes conventional open-hole well logs, borehole images, nuclear magnetic resonance (NMR) logs, Elemental Capture Spectroscopy (ECS) logs, formation pressure measurements, and routine core analysis. The porosity partitioning model allows the core porosity-permeability relationship to be reproduced from logs by incorporating dual porosity information. The integration of NMR logs and image logs used in the porosity partitioning model provides a well log based permeability that has a good correlation with core plug data.
Fracture and Sub-Seismic Fault Characterization for Tight Carbonates in Challenging Oil-Based Mud Environment—Case Study From North Kuwait Jurassic Reservoirs
Authors: Li Bingjian , Al-Awadi Mishari , Perrin Christian , AL-Khabbaz Mohammed , AL-Ashwak Samar , AL-Qadeeri Bashar
Published: March 2009

Evaluating natural fractures in tight carbonate reservoirs during the exploration and early development stages is critical in order to reduce geological uncertainty and determine well trajectory in future horizontal drilling. Challenges are often found in both acquiring the adequate data and assessment of the fractures/sub-seismic faults in the oil based mud borehole environment.

This paper summarizes part of the experience learned from the use of an optimal dataset in addition to a workflow on fracture characterization for tight deep carbonate reservoirs in Kuwait. In the process of exploration and development of these particular reservoirs, oil-based mud has been used in the drilling process due to the concerns of wellbore stability. Acoustic images and core was acquired in the early stages of the field development. After the invention of a micro-resistivity imaging tool it was used in combination with the acoustic imaging for integrated and enhanced formation evaluation, which allowed reduced coring for a cost saving. The paper explains the advantages and limitations of each image dataset and describes how the acoustic and micro-resistivity images are complementary to each other. The paper also presents how different datasets gives partial contribution to the overall geological understanding of the field. More importantly, the case study shows that the combination of both image data sets provides a much better and more complete picture of fractures in the wellbore with limited core calibration. Smaller scale faults, which are usually not detected or poorly imaged on seismic, can be interpreted on images with definition of vertical displacement through the integration of well correlation and cross sections. The output from this study provides an essential database for well completion decision, fracture reservoir modeling, infill drilling plan and future horizontal well placement.
Lessons Learned From the First Water Flood Pilot Project in a Clastic Reservoir in the Greater Burgan Field in Kuwait
Authors: Al-Naqi Meqdad , Al-Kandari Ibrahim , Al-Qattan Mishari , A/Rahman Badria , Bou-Mikael Sami , Gazi Naz H.
Published: March 2009

Greater Burgan in Kuwait is the second largest field and the largest clastic reservoir in the world. Discovered in 1938, the production initially came from Wara sandstone and soon followed by other underlying Burgan clastic reservoirs. Burgan reservoir mainly consists of three reservoir units namely Wara, Third, and Fourth sand. The Wara Water Flood Pilot Project is the first clastic waterflood pilot in Kuwait.

Reservoir pressure in Wara has been falling below the bubble-point in many parts of the reservoir. This would ultimately result in free gas evolving from the oil and significant loss in reserve recovery. This pilot was designed with the objective to obtain information in the areas of: Long-Term InjectivityReservoir ConnectivityWater Breakthrough Time and DirectionWater-Cut DevelopmentProductivityOperational Experience

The Wara pilot pattern is of inverted seven spot with one injector, six producers, and one water source and was designed to inject 5,000 to 10,000 bwpd into a single injector and to produce from six producers drilled around the injector. Each well is 250 meters apart and the producers are equipped with ESPs to produce even after water breakthrough.

The project has been in the operational phase for the last two years and the main objectives of evaluating long-term injectivity and the reservoir response to water injection in the Wara reservoir were achieved.

Results from this pilot were needed to reduce subsurface uncertainty and to support the design of future Wara waterflood projects. This will ultimately help in the decision of whether to build a permanent water flood project to maintain a stable reservoir pressure in the Wara reservoir.

This paper highlights the challenges and accomplishments in designing, completing, and operating of this successful water flood pilot project which could benefit other similar projects around the world.
From Data Acquisition to Simulator: Fracture Modeling a Carbonate Heavy-Oil Reservoir (Lower Shuaiba, Sultanate of Oman)
Authors: Warrlich Georg M. D. , Richard Pascal D. , Johnson Timothy E. , Wassing L. Bart M. , Gittins James D. , Al-Lamki Ali , Alexander David M. , Al-Riyami Murshid
Published: March 2009

A dedicated appraisal campaign and modeling study was carried on a heavy-oil, fractured Shuaiba field in the north of the Sultanate of Oman to assess the feasibility of steam-assisted gas-oil gravity drainage (SAGOGD) EOR. In this field, key to a successful SAGOGD is a well-connected fracture network, which was investigated by a dedicated appraisal campaign which included drilling one vertical and 3 near-horizontal wells. BHI, sonic and resistivity logs were run to understand static fracture characteristics; dynamic behavior was assessed with DSTs and PLTs. Fracture models were built with forward modeling algorithms using Shell's fracture modeling software (SVS Fracture-Solution). They are based on fracture characterization that integrates the well data with 3D seismic, field kinematic structural evolution and the regional understanding established by Petroleum Development Oman's (PDO) long-term activities in the area. This integration makes the fracture models more realistic than purely stochastic fracture models that only honor the statistical field data.

Interdisciplinary collaboration during data acquisition and all stages of the modeling assured that only the features relevant to the dynamic behavior of the reservoir were modeled while at the same time the geological details of matrix and fracture models were captured sufficiently in the simulator. Simulations were run in dual porosity dual permeability thermal mode in Shell's dynamic simulator (MoReS). The results are fully integrated model scenarios that can be compared quantitatively with all other PDO fractured Shuaiba fields, facilitating management's technical decision making on the EOR strategies for the fields.
Full-Field Development Plan "The Big Picture—Creating the Future from the Future and Success through Real Synergy"
Authors: Hafez Hafez H. , Kenawy Maher M. , Keshka Ashraf Al-Saiid , Samad Khalid Abdul , Al-Bakr Salem , Al-Dhiyebi Shaffique
Published: March 2009

This paper represents a case history of a full-field development plan for one of the major fields (field "A") in Abu Dhabi Company for Onshore Oil Operations (ADCO-UAE) consisting of three different reservoirs. Field (A) development is becoming increasingly complex and expensive as this field acts as a hub for another two producing fields and several undeveloped fields. This involves developing an efficient design and planning philosophy. Best practices in integrating new technologies in materials, construction, operations as well as management techniques including the right team to really be successful are all part of the "big picture".

ADCO assigned a cohesive and highly motivated team involved in the ‘big picture" event with a clear direction in terms of policy, risks and implementation aimed to shorten the decision process without compromising the company Major Project Approval Process (MPAP) requirements and Shareholders guidelines.

The Project Management main factors that were tackled successfully during this event were the focus on profitability and increase of NPV by adopting a multi-disciplinary approach to field management; align various departments involved right from the concept to the implementation stage through continuous interaction; cultivate an open-ended approach to all aspects of engineering and Field Management by taking into account both the surface and subsurface perspectives of oilfield Project Management.

The paper will also address the structure of the team and how it set feasible targets in terms of production building blocks of other fields through eventual expectations in terms of surface facilities and helped in overcoming challenges and minimizing risks through careful integrated risk register. Finally assessed specific problems and issues relevant to the field operability and evaluate possible strategies to tackle it.

The key objective and achievements of the event were the deliverables for the Stage-4 of the MPAP. The paper will discuss the achievements as a result of this event. The integration of the development options alternatives, into a single development plan enabled shortening the decision process and secured Shareholders approval on Gate-5 finance proposal as it was recognized as an economically favorable development opportunity. The development plan continued to other Gates (7 & 9) with the same approach in order to properly accomplish the success of such plan with a value of multi Billion USD.
Specialized Techniques for Formation Testing and Fluid Sampling in Unconsolidated Formations in Deepwater Reservoirs
Authors: Jackson Richard R , De Santo Ilaria , Weinheber Peter , Guadagnini Emilio
Published: March 2009

Wireline formation testing (WFT) and fluid sampling has long been used for determination of reservoir pressure, evaluation of fluid type from in-situ densities, identification of fluid contacts, and inter-reservoir connectivity. Fluid sampling and downhole formation fluid analysis measurements also provide information for assessment of fluid complexity, compositional grading, and acquisition of samples for input to PVT studies.

Many deepwater reservoirs comprise of young turbiditic formations, which even at great depths remain unconsolidated or only weakly cemented. Experience has shown, when sampling fluids from such formations, sand grains and solids tend to become mobilized and flow with the fluid being sampled. In some circumstances where significant formation solids and sand are mobilized, deposition of suspended solids can result in the premature ending of formation testing and sampling jobs, or require multiple trips into the well to acquire the required samples and fluid profiling stations.

To limit excessive sanding and solids production, and mitigate problems of plugging during sampling operations, the conventional approach has been to reduce the pressure drawdown, and limit pump speed and flow rates. To increase tolerance to solids production during sampling operations, various filter and pump options are available for the different probe, focused probe and dual packer tools - as well as enhancements to improve pump performance in the presence of high solids content. Such approaches are not always successful.

In this contribution we describe an innovative solution to unconsolidated sanding problems during sampling and advanced fluid profiling, and its practical application for deepwater exploration and appraisal operations using several field examples. Suspended solids pass through an inline filter sensor module, where the particles are trapped and deposited, allowing fluid with little or no particles to pass through the formation tester tool. This results in greater reliability and efficiency for formation testing and sampling in unconsolidated formations.
Climate Change: Facts, Science & the Dispute Regarding the Environment
Authors: Hamilton J. , Vossoughi S.
Published: March 2009

The measured increase in the Earth's temperature combined with a rise in average ocean temperatures, have prompted predictions of catastrophic results from severe global warming. The climate change and the variety of causes with which it is associated are being reviewed here.

The paper reveals that the experts in this field are distinctly and passionately in disaccord. The only point the opposing scientists agree on is that there is some level of global warming. There is little, if any, agreement on any other aspects of the subject matter.

Current measurements show a marked increase of average air temperature near the Earth's surface, especially within the last decade. Moreover, these increases in temperature have caused scientists to further examine and predict future temperature changes. These changes present a dire outlook that lead to drastic results for the environment and future human activity through the 21st century. Despite research and data that support the accuracy of the causes, there are prominent scientists that dispute the theory that human activity and the industrial economy are the root causes of climate change. Undoubtedly, the natural cycles of both the sun and Earth are the underlying causes of expected and cyclic changes. These cycles, however, do not account for the sharp increase in the overall warming trend witnessed recently. Greenhouse gas emissions as a result of human activity have negatively affected the environment and will continue to do so if left unchecked. The potential of global warming and the implications of climate change are fueling the most contentious debates in business, science, and politics. With questions of glacier dissipation, environmental irresponsibility, and the future instability of the planet, world leaders are increasingly more focused on cleaner energy, correcting years of neglect, and ensuring that the amount of greenhouse gases is decreased.

Overall, it is believed that human activity has contributed a great deal towards the climate trends we are experiencing on a global level. Without large-scale buy-in of several of the mitigating actions, the warming will continue and human activity will persist in altering the environment. With current political developments regarding revised Kyoto policies, a more effective and efficient stance by emissions-producing countries and a commitment to re-examining our energy sources, the trends can be slowed and ultimately reversed.
Measurements of Streaming Potential for Downhole Monitoring in Intelligent Wells
Authors: Jaafar M. Z. , Vinogradov J. , Jackson M. D. , Saunders J. H. , Pain C. C.
Published: March 2009

Downhole monitoring of streaming potential, using electrodes mounted on the outside of insulated casing, is a promising new technology for monitoring water encroachment towards an intelligent well. However, there are still significant uncertainties associated with the interpretation of the measurements, particularly concerning the streaming potential coupling coefficient. This is a key petrophysical property which dictates the magnitude of the streaming potential for a given fluid potential. The coupling coefficient can be measured experimentally, but previous studies have obtained data for sandstone cores saturated with relatively low salinity brine (less than seawater). Formation and injected brine in hydrocarbon reservoirs is typically more saline than this. Extrapolating data obtained at low salinity into the high salinity domain suggests that the coupling coefficient falls to zero at approximately seawater salinity. If this is the case, then streaming potential signals will be very small in most hydrocarbon reservoirs.

We present the first measured values of streaming potential coupling coefficient in sandstone cores saturated with brine at higher than seawater salinity. We find that the coupling coefficient is small, but still measureable, even when the brine salinity approaches the saturated concentration limit. Consistent results are obtained from two independent experimental setups, using specially designed electrodes and paired pumping experiments to eliminate spurious electrical potentials. We apply the new experimental data in a numerical model to predict the streaming potential signal which would be measured at a well during production. The results suggest that measured signals should be resolvable above background noise in most hydrocarbon reservoirs, and that water encroaching on a well could be monitored while it is several tens to hundreds of metres away.