bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multistage Acid Fracture Effectiveness in Gas Production in the Carbonate Reservoir, Saudi Arabia - Study and Analysis of Field Examples
Authors: Islam Ashraf , Rahim Zillur , Al-Anazi Hamoud A. 
Published: March 2015

Abstract
For last few years, multistage acid fracture treatments have become a common practice to develop the carbonate gas reservoirs in Saudi Arabia. Different multistage completions systems have been used in more than 50 wells that were acid fractured anywhere from 2 to 6 stages per lateral. These systems include multistage fracturing (MSF) with openhole frac sleeves in combination with open hole hydraulic or swellable packers to provide zonal isolation between fracture stages. This paper provides an analysis of the effectiveness of these fracturing treatments comparing the pre- and post-frac gas production rates of the wells as functions of fracture half-length, conductivity, and some of the main reservoir properties such as porosity and flow capacity.
One major concern from the open hole MSF treatments is the zonal isolation provided by the open hole packer assemblies. This is very important to ensure fracture containment for the zone the induced fracture is intended for. Failure in isolation can lead to communications between intervals allowing the pumped frac stage to propagate to the previously opened frac stage. This could result in fracturing less number of stages than designed. Consequently, the expected production rate may not be achieved. This study also analyzes the post-frac pressure build up response for selected carbonate reservoir wells to compute number of effective fractures created during the treatment. The reason of isolation failures and how to avoid that in the future MSF treatments are discussed in this paper. Several field data including post-frac production data have been analyzed for MSF acid fracturing in the carbonate gas reservoirs to establish the treatment effectiveness. This analysis will be useful to optimize the future well stimulation programs and improve gas production.
Technology Improvements in the Giant Manifa Field Maturation Project
Authors: Arukhe James O. , Duthie Laurie S. 
Published: March 2015

Abstract
Several improvements were necessary in the Manifa giant oil field development to secure a superior or favorable business position through the deployment of value-adding technological solutions in rigless interventions. Developing a field is often like solving a typical problem of constrained optimization, in this case, to maximize field development outcomes from well intervention (leading to improved production) subject to certain constraints. The constraints in the giant Manifa field maturation project case include the state of technical knowledge to access its extended reach wells, allocated budget for intervention, or to protect the environment. Thus, the optimization problem is to determine the bundle of technologies which maximizes the field's well intervention strategy subject to technology, budget, or environmental constraints. The improvements are necessary to intervention outcomes dividends and to overcome several technical difficulties in the field.
The scope of the paper is to examine technology improvements in coiled tubing (CT) reach and stimulation treatments specifically. CT reach technologies have improved to include elaborate physics or design aided simulations, which includes a consideration of friction coefficients, prediction or estimation of the lock-up points, selection of the amount, concentration, and volumes of friction reducers. The simulation offers guides to engineers with available methods for additional CT reach including the use of flowing fluid, downhole tractors and agitators, straightening, pipe size, and optimal taper of CT, drag/friction reducers, and buoyancy reduction. The advent of robust tractors that provide external pulling force on CT has increased CT reach especially on power water injectors. However, uncertainties remain in determining tractor performance, quantifying the tractor actual pulling force, fine-tuning friction coefficients, early detection of CT tags, and differentiating between CT tag and excessive drag.
Stimulation treatments have improved from bull heading stimulation fluids into the wells with limited zone control. The use of CT for matrix stimulation treatments to optimize acid placements seemed to have helped to enhance diversion and acid placements through a combination of distributed temperature sensing, pressure, temperature, and casing collar locator real time measurements. Self-diverting viscoelastic diverting acid (VDA), designed to viscosify in situ as the fluid spends on the reacted formation for chemical diversion in carbonates have been optimized from 20 % HCl to 15 % HCl. Technologies which allow the measurement of bottom-hole parameters in real time enabled the conduct of deeper reach CT for enhanced stimulation practices. The improvements are significant because real-time capabilities can significantly improve the quality of well interventions and decision making in the field.
Invasion Corrected Fluid Saturations, from Standalone Consonant Nuclear Measurements, Using Canonical-Correlation Analysis (CCA) of Logging-While-Drilling (LWD) Time-Lapse Data
Authors: Al-Daghar Khadeeja A. , Atfeh Mudar M. , Aal Atef F. , Jain Vikas , Murray Doug R. , Minh Chanh Cao , Gzara Kais 
Published: March 2015

Abstract
Fluids saturations in new wells are usually derived from resistivity measurements, using locally selected or calibrated resistivity equations. Some drawbacks to resistivity measurements are multiple environmental corrections in high-angle wells, thin beds, washed-out boreholes, and complex invasion profiles. Moreover, the accuracy of Archie's equation may suffer from variable cementation and saturation exponents and unknown water salinity.
A recently introduced comprehensive suite of consonant logging-while-drilling (LWD) nuclear measurements with linear mixing laws, is used to solve for minerals and fluid volumes independent of resistivity measurements. This requires the petrophysical properties of all the fluids present to be known. Another requirement for accurate formation evaluation is the mud filtrate invasion correction. While this poses no problem for multiple depths of investigation (MDOI) resistivity measurements that also read deep into the formation, there is no set rule to determine the geometrical factor of nuclear measurements to account for invasion.
This paper describes an LWD time-lapse data acquisition scheme to circumvent invasion effects on nuclear measurments and to eliminate the need to specify some of the unknown petrophysical properties of the fluids present. Canonical-correlation analysis (CCA) is used to identify canonical variates that remain unchanged between a primary drill pass and a secondary wipe pass. Because these variates remain unchanged between passes, they are independent of the formation invasion status, and can represent the properties of either the virgin or the flushed zone, but not a combination of the two, as is typically the case of measurements whose volume of investigation samples both zones. These invasion-independent variates are then used in the petrophysical evaluation, instead of the standard logs which may otherwise vary with time.
We used CCA in 2 carbonate examples to show how to 1) correct bulk density measurement in corkscrew borehole, 2) correct MDOI capture sigma measurements for invasion effect, and 3) perform volumetric formation evaluation without knowledge of the water and hydrocarbon endpoints and invasion parameters. The CCA approach is a significant new development in well log interpretation that removes uncertainties associated with unknown mineral or fluids petrophysical properties and invasion status.
Evolution of Chemical EOR (ASP) Program for a Carbonate Reservoir in North Kuwait
Authors: AlAbdullah Mohammad , Tiwari Sanhita , Pathak Ashok 
Published: March 2015

Abstract
Sabiriyah Mauddud (SAMA) is not only a giant reservoir in North Kuwait with largest footprint it is also the most complex being carbonate. Presently, this reservoir is under waterflood which has helped to improve reservoir pressure and production performance.
Production strategy of 1 million BOPD from NK reservoirs has brought focus on accelerated oil production by drilling new wells, good reservoir management practices and targeting difficult reserves. Possibility of early implementation of EOR has been considered as an option for SAMA.
EOR screening studies were followed by extensive laboratory coreflood studies and sector model simulation study. In Lab, carefully designed recipe of chemicals (Alkali-Surfactant-Polymer) successfully addressed the critical issues of conformance control and adverse mobility ratio observed in SAMA to provide high displacement efficiency. Sector model was carried out to evaluate the different EOR processes like, gas, polymer and Surfactant-Polymer (SP). Encouraging oil recovery results were observed in lab and in sector model study with Chemical EOR which paved the way forward for testing it in reservoir.
Success achieved through bench experiments and simulation study was transferred to the field last year when Single Well Chemical Tracer Tests with water and ASP recipe were conducted in three SAMA wells with successive improvement either in test procedure or in chemical formulation of the ASP. The result of the last test with ASP paid for all the hard work that was done with Sor brought down to 6%.
Encouraged by these results, a small 6-acre inverted 5-spot pilot for Sabiriyah Mauddud is planned for 2016-17 success of which is a significant step for field wide implementation of EOR program.
Extending Values of a PDHMS System to Production Optimization
Authors: Mei Ken 
Published: March 2015

Abstract
Over the last decade, many permanent downhole pressure and temperature gauges (PDG), also called permanent downhole monitoring systems (PDHMS), have been installed globally in many oilfields. One primary objective of installing permanent downhole gauges in a wellbore is to avoid field trips with a wireline unit for pressure surveys. Additionally the system can turn any well “shut-in” time into a valuable opportunity for both a pressure survey and a build-up testing, significantly improving the reservoir surveillance frequency. Only a few authors have conducted a systematic analysis and explored the potential application of a PDHMS system.
This paper briefly describes the elements of a typical PDHMS monitoring system. A detailed systematic analysis is presented for the first time, including factors affecting the application of such a system. Our analysis reveals that the accuracy of the pressure gauges, gauge installation, depth and the distance between the two pressure gauges have a significant impact on the application of a PDHMS system. Improperly choosing the accuracy of pressure gauges, randomly placing the pressure gauges in a wellbore, or improperly setting a distance between two pressure gauges could result in little benefits from such practice. The analysis presented in this paper enables petroleum engineers to make the sound engineering decisions during the planning of PDHMS installation.
Our study presented in this paper extensively includes an investigation of the specific requirements of such a system in different types of wells (producers and injectors) and explores their potential applications. This study extends the application of a PDHMS system to a new horizon in terms of production optimization and reservoir surveillance. Also presented in this paper are some cases showing how real time PDHMS data is utilized for continuously monitoring reservoir pressure changes, and optimizing both testing frequency and wellhead sampling requirements in a Saudi Arabia field.
Application of Fast Reservoir Simulation Methods to Optimize Production by Reallocation of Water Injection Rates in an Omani Field
Authors: Al Saidi A. , Pourafshary P. , Al Wadhahi M. 
Published: March 2015

Abstract
There are wide and crucial applications of the reservoir simulation to develop, manage and monitor reservoirs. However, the traditional simulation methods have different limitations such as noticeable necessary time to prepare and model data and uncertainties in the available data. Therefore, new approaches are developed to offer rapid reservoir simulation with lower and more reliable data to manage and optimize production from hydrocarbon reservoirs and provide us a quick estimation of the performance of the reservoirs. One of these approaches is the Capacitance-Resistive Model (CRM).
CRM is a quantitative technique based on material balance that uses only injection/production rates and well coordinates to identify and quantify reservoir model parameters, which are well connectivity and time constant values. In CRM, the reservoir is assumed as a system where the injection rates are the input signals and the production rates are the output signals. The injection performance over a period of time can be identified by estimating fractions of injected fluid to each producer and the time taken for a producer to sense the injections. With CRM, it is possible to optimize a waterflooding operation in a field by reallocating the water injection rates to optimize the oil production. This tool is preferred due to its simplicity, the short computation time and the use of available field data.
In this study, we developed a new approach to use the Capacitance Resistive method to optimize the waterflooding process in an Omani oil field by a ranking approach for the injectors. By reallocation of the available water to injectors, the future oil production was optimized for the next three years. This method showed that the optimized scenario leads to 29.90% increase in future oil production compared to the current injection rates profile. This was achieved by injecting 59% of available water for most effective wells and the remaining amount for other wells.
A Full Scale Two-Phase Flow Loop Test of Downhole Permanent Multiphase Flow Meter
Authors: Saeed Abubaker , Noui-Mehidi Mohamed N. , Black Michael J. , Abbad Mustapha , Shafiq Muhammad 
Published: March 2015

Abstract
This work presents a joint collaboration effort between Saudi Aramco and Schlumberger for the qualification of a new generation of downhole permanent multiphase flow meter. We report the validation test of a new permanent completion tool, which is planned to be deployed in horizontal and multi-lateral wells. The field deployment requires the installation of several stations of the tool for an efficient zonal monitoring and control of the reservoir. Each metering station has a miniature flow meter, water cut sensor and an electro-valve which can be controlled by the operator to prevent the water breakthrough in the production tubing and optimize the oil production. Before the field installation, a unique full scale two-phase flow loop was built in Saudi Arabia specifically to test the accuracy of the metering devices. A complete physical modeling campaign was designed to model the flow of oil and water in downhole conditions through appropriate matching of defined flow non-dimensional numbers. The experimental tests showed excellent results with accurate monitoring of the produced fluids and a smooth control of the oil production.
Drilling Professional Development Program (DPDP)
Authors: Mohammad Rahman , Mamdouh Agawani , Eiman Hazza 
Published: March 2015

Abstract
Shortage of qualified, experienced and competent drilling professionals is worldwide, especially among Saudis within the Kingdom. Visualizing the Saudi Aramco management intension to develop home-grown talent, the D&WO HR Training Division has taken up an accelerated and challenging training initiative “Drilling Professional Development Program” (DPDP) to develop the fresh engineers and prepare them to be professional drilling foremen and drilling engineers. This paper outlines how the Training Division has planned and implemented this unique program to tackle technical manpower requirements through a comprehensive, structured, and knowledge-based competency program utilizing the diverse training methods.
Executing such a training program is expensive in short-run but provides multiple returns on the investment in the long-run. This will be felt when the Saudi talent takes over D&WO operations, and the dependency on expatriates begin to diminish. The impact on the targeted Saudization not only can be cost effective but also ensure high level of competent professionals. This paper explains the DPDP program development, challenges, results and the lessons learned.
Heavy Oil Characterization: Lessons Learned During Placement of a Horizontal Injector at a Tar/Oil Interface
Authors: Lyngra Stig , Hursan Gabor G. , Palmer Richard G. , Zeybek Murat , Ayyad Hazim A. , Qureshi Ahmed 
Published: March 2015

Abstract
A case history is presented for a horizontal injector drilled at the base of a moveable oil column on top of a tar mat in a carbonate oil reservoir in the Middle East. The well was placed utilizing real-time Logging-While-Drilling (LWD) Nuclear Magnetic Resonance (NMR) oil viscosity correlations and formation tester mobility data.
As a pilot water injector, placed at an oil/tar interface with restricted historic oil viscosity versus depth data, obtaining calibration oil samples was considered critical. Both LWD and pipe-conveyed (TLC) formation tester data sets were acquired, which made direct comparisons of LWD and TLC acquired formation pressures and formation mobilities possible. The comparison proves the reliability of the LWD formation mobilities. The LWD measured formation pressures were supercharged while the TLC formation tester formation pressures were largely in line with expected formation pressures.
The oil viscosity results from the TLC formation tester in-situ viscosity fluid analyzer and the NMR viscosity correlation compared favorably with the laboratory results from the acquired TLC formation tester fluid samples. This indicates that accurate real-time in-situ fluid property determination is possible with modern formation tester and NMR tools.
In this reservoir, at an early phase of acquiring oil/tar transition zone oil viscosity versus depth data, the main lesson learned was that the deeper section of the case study well contained higher asphaltene content than expected, which caused wellbore plugging that prevented reservoir access after suspending the well for tie-in. A clean-out operation was unsuccessful as plugging reoccurred. The well is now planned to be re-sidetracked in 3-20 centiPoise (cP) oil at the top portion of the oil/tar transition zone.
Wellbore Stability Analysis in Depleted Deepwater Reservoirs: A Case Study from Australia
Authors: Asadi M.S. , Khaksar A. , White A. , Yao Z 
Published: March 2015

Abstract
The formation fracture gradient (FG) in deepwater environments is lower, compared to that in shallow water and onshore fields. Consequently, narrow margin drilling is generally a challenge in deepwater fields. The FG is sometimes different from the principal minimum horizontal stress (Shmin). The FG may be determined from the fracture initiation pressure (FIP) or from the pressure required for the fluid to leak off through conductive natural fractures. In contrast to the Shmin, the FIP is a function of wellbore trajectory.
In this study, we present data from a deepwater gas field in Australia. The Shmin profile was calibrated against extended leak-off tests (XLOTs), microfrac, and injectivity tests in 12 offset wells using log-based poro-elastic and effective stress ratio (ESR) methodologies. We then constrained and calibrated the geomechanical model using a range of well logs, drilling data, and core experiments. The geomechanical model was used to calculate the FIP and its variation with borehole trajectory for a number of horizontal wells under initial and depleted conditions. The results show, for particular well trajectories, the mud weight window (MWW) is extremely narrow if the FG is considered to be equivalent to the FIP. In addition, Shmin tends to be low in reservoir sandstones, which will make the drilling of high-angled wells in the depleted zones challenging. If natural fractures exist in the reservoir, fluid may leak through the fractures in which conductivity could be enhanced by shear slip with a hole pressure less than both Shmin and FIP. We used the Mohr-Coulomb sliding criterion to identify the population of fractures in the reservoir most susceptible to shear slip. The results indicated that high-angled fractures that strike NE-SW may become critically stressed during drilling, meaning they are prone to slip and may lead to fluid losses with the bottomhole pressure (BHP) less than the FIP. The results of this study led to revisions to the planned well trajectories. We optimized the trajectories to take advantage of higher FIP (relative to Shmin) to reduce the risk of fluid losses into natural fractures. In addition, we considered depletion in the reservoirs for optimization.
Technology-driven Approach to Develop Shale Gas in Saudi Arabia
Authors: Bartko Kirk M. , Coffin Brian , Tineo Roberto 
Published: March 2015

Abstract
Early in the 1980s, efforts started to be made to develop the now famous Barnet Shale. It required 20+ years of drilling and completion innovations to make it commercially viable. The Barnett was the starting point to develop other plays in North America such as at Fayetteville, Marcellus, Haynesville, Woodford, and New Albany. It is important to note that success in shale production has been the result of years of work of many companies (mostly small independent operators) drilling thousands of wells, learning from each other, and ultimately developing the so-called factory approach to drilling and completions.
Unlike the U. S., Saudi Arabia does not have the luxury of thousands of penetrations through its shale gas plays; particularly critical is the absence of other operators to share experiences and risks. Therefore, Saudi Aramco decided to explore its shale gas resources in the Kingdom by adopting a “technology driven” approach against the U.S.-based “factory” or “statistical” approach.
The “technology-driven” approach and the customized workflow applied in this project have minimized the time required to understand the reservoir and apply technologies appropriate for their completion. To date, this workflow has been utilized and calibrated with single well analysis. As sufficient amounts of data, especially 3D seismic data, which is currently being shot in the northern region of Saudi Arabia, becomes available, this workflow can be further enhanced and calibrated with a three-dimensional regional model. A wellbore calibrated workflow based on the pilot hole data, learnings from surrounding holes, and North American organic industry experience can substantially shorten the learning curve in Saudi Arabia.
This paper demonstrates a customized workflow developed for Saudi Arabian shale gas plays and shares the preliminary results of the project.