bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of an Integrated Reservoir Surveillance Process for World's Second Largest Field in Kuwait
Authors: Desai Sameer F. , Al-Ajmi Hussain Z. , Al-Humoud Jamal H. , Gazi Naz H. 
Published: March 2009

Abstract
The Greater Burgan Field in Kuwait is the largest clastic reservoir and the second largest field in the world accounting for most of the oil produced in the country. Discovered in 1938 it has over 1000 wells drilled to date. New wells are being added every year to this field to meet the production strategy of Kuwait Oil Company. It is becoming extremely important to identify and perform focused surveillance work to have a better understanding of the reservoir, drainage mechanism, remaining potential and pressure decline.
A huge amount of data accumulates every year leading to questions whether acquiring so much data is really justified. Techniques and processes used to acquire surveillance data to detect anomalies and the routine monitoring needs had to be quantified to assess the value of information. Thus a detailed study was undertaken to review the historic surveillance activities and the interpretation of the acquired data. The value of increased surveillance was highlighted through a dual approach of a quantitative and a qualitative analysis through which incremental benefits were achieved both directly and indirectly such as increased oil production, reduction in produced water, finer tuning of simulation models and sub surface maps.
The study concluded that the necessity for up to date surveillance data is justified by its importance for generating value based information for: Well performance and nodal analysis for production optimization and improved recoveryReservoir management and monitoringMappingSimulation studies for reservoir characterization, depletion mechanism and reserves addition
This paper describes the approach taken in the study towards the development of an integrated reservoir surveillance plan for monitoring the massive Burgan Field and highlights the challenges and accomplishments in this process. It covers the designing, completing, and operating aspect of this successful plan which can be used in other fields around the world.
PDO FEED Office Value Proposition
Authors: Al-Balushi Abdulnabi , Jeganathan Xavier , Flewker-Barker Ian 
Published: March 2009

Abstract
The Petroleum Development Oman (PDO) projects portfolio is going through a significant change as its oil and gas fields mature. In addition to the large number of repetitive brownfield developments, there is now an increase of major projects as Enhanced Oil Recovery opportunities mature. In addition, a number of major gas compression projects need to be implemented.
To sustain its oil and gas production PDO require to implement several major projects over the next ten years, each in the range from $ 100 mln to $ 2.0 bln.
PDO experience demonstrated that value improving practices are linked to improved capital project outcomes. Value improving practices are out-of-the-ordinary practices used to improve project performances and they are primarily used during initial phases of project i.e. from identifying the opportunity to define Front End Engineering Design (FEED) phase.
Due to lack of in-country FEED capability, all major FEED works were carried out abroad by International Design consultants and this FEED package was issued to Engineering Procurement & Constructing Contractor for Bidding / Detail Design purposes.
These FEED packages were resulting in followings deficiencies:- Insufficient FEED definition leading to risks and uncertainties during detail designMultiple changes to design at significant cost and schedule impactLack of Adequate Analysis of Potential SolutionsUnrealistic Plan/budget (optimistic forecasting)Continued loss of potential optimisation from the leverage opportunities that existRework due to changes in parallel activities in the same area lead to discussion on commercial/contractual terms, which causes delay in absorption of changes in FEED work.Lack of standardization of designPoor operability and maintainability of plantPoor first year + availability of new plant
Ultimately these deficiencies were leading to prolonged project completion cycles and delay in production. In view of these FEED package deficiencies and increase in PDO portfolio of major projects and the scarce market resources, PDO established in-house FEED capability. This reduces project lead time, improve project definition prior to the Final Investment Decision (FID) and will provide development opportunities for Omani staff. The 60 staff FEED capability was established with in-house resources, supported by a capable contractor. Training of PDO Omani staff in the additional skills was carried out in Q2 – Q4 2007 in a highly professional FEED office, while in the same period, office, Information technology (IT) infrastructure established and a support contractor was selected.
Sweep Impairment Due to Polymers Shear Thinning
Authors: AlSofi Abdulkareem M. , LaForce Tara C. , Blunt Martin J. 
Published: March 2009

Abstract
Most polymers used in EOR exhibit shear thinning behavior. At least theoretically, shear thickening will improve sweep while shear thinning (pseudoplasticity) will impair it through exacerbating the velocity contrast and/or inducing instability. Despite this, the effect of pseudoplasticity on sweep has not been studied in detail.
An in-house streamline simulator has been extended to handle polymer flooding with Newtonian and non-Newtonian behavior. Three main modifications were implemented. First, the polymer mass balance was solved along the streamlines. Second, a polymer multiplier was defined to account for polymers' viscosifying and thinning effects. Finally, an iterative approach was implemented to solve the pressure field. This is needed since the pressure depends on the aqueous phase viscosity, which for non-Newtonian fluids depends on shear stress, and hence the pressure itself.
The simulator was then used to investigate pseudoplasticity effects on sweep and recovery in various reservoir models. Two cases were run. The first had a stable connate bank; hence, thinning does not induce instability and the only effect is velocity exacerbation. The second had an unstable connate bank; hence, thinning can induce instability.
The results of this work prove the importance of taking polymers' non-Newtonian behavior into account for the successful design and evaluation of polymer flooding projects. This is because pseudoplasticity will impair sweep, which can deteriorate the whole economic picture of a polymer flood. Even if instability is not induced, more pore volumes will be needed, more water will be produced, and in light of a limiting water cut, less oil will be recovered; in other words, higher operations costs, higher processing costs, but less profit. Simulations carried in a 2D heterogeneous model suggest that for unconditionally stable flooding, the injection requirement will double from 2 to 4 pore volumes. In addition, in light of an 80% limiting water cut, a thinning fluid would decrease recovery by 2% of OOIP compared to a Newtonian fluid. Furthermore, if thinning does induce instability, shear thinning will reduce ultimate recovery. Simulations carried in a 2D heterogeneous model suggest that a pseudoplastic fluid would decrease recovery by 5% of OOIP compared to a Newtonian fluid.
Opportunistic Pressure Data Gathering Campaign During Production Shut Down—Added Insight Into the Water Flood Response and Pressure Connectivity in a Highly Heterogeneous Clastic Reservoir in North Kuwait
Authors: Baroon Bodoor , Chetri H. B. , AL-Anzi Ealian 
Published: March 2009

Abstract
Upper Burgan is a sandstone reservoir in North Kuwait, which is a depletion drive reservoir predominantly, with a very weak aquifer support. The reservoir has cumulatively produced about 7% of oil in place since its discovery. Almost 90% of production in the historical past came from the crestal area leading to a rapid decline in reservoir pressure. The initial reservoir pressure was about 3800 psia and it is continuously declining to bubble point pressure. Recently water flood has been initiated at three of the injectors in the crestal area to reverse the trend of pressure decline.
Pressure monitoring is the key for the monitoring heterogeneous Upper Burgan reservoir, currently under water flood. This has been achieved in three ways during past 5 years: Time lapse SBHP monitoring; isochronal full field pressure surveys during reservoir shutdown and PBU/PFO /RFT/ data integration with PLT & Production tests. Extensive data gathering has enabled the team to enhance the water flood response. Additionally, smart maps using OFM have also been created as tracking tools.
The pressure monitoring & analysis has helped in effective water flood management as well as sustaining the production rates for this challenging heterogeneous reservoir. Also, the extensive data acquired and analyzed has added value to the comprehensive channel description, reservoir continuity and simulation model update for this reservoir.
The objective of the paper is to share the approach adopted by us and experiences gained during last 5 years of water flood monitoring in North Kuwait.
Reservoir Re-Appraisal Through Multi Model Analysis of Pressure Transient Test in Horizontal Well in Giant Carbonate Reservoir
Authors: Alrefai Sayed Abdulrahman 
Published: March 2009

Abstract
Reservoir characterization through reservoir re-appraisal in a flank area of Mauddud giant carbonate reservoir has opened a new area for reservoir development. Reservoir re-appraisal of this reservoir, which is located in Sabiriyah field of north Kuwait, was mainly approached through lengthy pressure build up in a producing horizontal well. SA-0XX is the horizontal well which has been tested and analyzed the undeveloped pattern of the water flooding plan. This well is an important Mauddud reservoir well since it is located in the far most Northern pattern of SA-0YY injector. The performance of SA-0XX and the nearby well, SA-0ZZ, (which were flowing recently on continues basis due to submersible pumps ESP installation) have been very encouraging.
The pressure build up analysis (PBU) of SA-0XX (before ESP installation) has been analyzed. The test was interpreted with three deferent models. Since the well is located between two faults, the main variable of the three models was the effect of these faults. According of the geological and reservoir information, these faults are conductive but the test's match showed that the faults are sealing or infinite. The match of the test was obtained with horizontal well with homogeneous model and infinite boundary. Also it can be concluded that the flow is not reaching the fault because of the boundary effect showed in the interpretations.
Evaluation of New Stimulation Technique to Improve Well Productivity in a Long, Open-Hole Horizontal Section: Case Study
Authors: Franco C. A. , Solares J. R. , Al-Marri H. M. , Garzon F. O. , Asiri K. S. , Saeed H. A. , Omairi W. M. , Izquierdo G. A. 
Published: March 2009

Abstract
Saudi Aramco has significantly increased the number of horizontal gas producers over the past five years in an attempt to maximize well productivity through maximum reservoir contact while reducing the need for hydraulic fracturing stimulation, commonly required in most vertical producers. Although the majority of horizontal producers have met expectations, a good number of them have underperformed showing lower initial gas rates and higher decline rates than anticipated. The unexpected poor performance in most wells has been attributed to induced formation damage during drilling operations, the highly heterogeneous nature of the reservoir resulting in low porosity and permeability in different areas of the field, destabilization and precipitation of mineral and organic scales in the tubulars and formation, and condensate banking effects.
The overwhelming majority of horizontal producers are completed open-hole, which significantly limits stimulation options once the wells have been completed and put in production. Moreover, high pressure and temperature conditions make accessibility of the horizontal section very difficult, and the chance for achieving successful stimulation of the entire horizontal section relatively low. Conventional stimulation treatments involving coiled tubing (CT) acid washes and bullheaded hydraulic fracture treatments have been attempted over the years but results have been mostly unsuccessful or relatively modest.
This paper details a case history of a new approach combining different techniques, which was successfully used to stimulate a long open-hole horizontal section in an underperforming gas producer. A hydraulic fracture treatment using hydrajetting technology, that provided the ability to achieve deep penetration into the targeted zone, resulting in effective treatment fluids diversion, was successfully pumped. A detailed analysis to ascertain the effectiveness of the procedure was conducted, the results of which are discussed in this paper.
A Novel Thermal Technology of Formation Treatment Involves Bi-Wellhead Horizontal Wells
Authors: Ibatullin R. R. , Ibragimov N. G. , Khisamov R. S. , Zaripov A. T. , Amerkhanov M. I. 
Published: March 2009

Abstract
The Republic of Tatarstan possesses significant reserves of heavy oil and bitumen (more than 1.4 bln. tons), major portion of which are found in the Ufimian and Kazanian stages of Permian age. About 450 deposits have been discovered at rather shallow depths, 50 - 250 m subsurface.
The first pilot project on heavy oil production through vertical wells dates back to 1970-ies. A number of thermal methods were tested including in-situ combustion, cyclic steam stimulation and gas-steam mixture injection. However, all these methods demonstrated their insufficiency.
In 2006, a new pilot project was launched. This is a modified technology of steam stimulation through a pair of U-shaped horizontal wells.
To date, three pairs of U-shaped horizontal wells have been drilled with the lengths of horizontal wellbores from 200 to 400 m. The wells were spudded vertically with a vertical drilling rig, hitting the surface at an angle, having thus two wellheads, vertical and slanted. The wells were completed from the surface: the casing with the sand screen was pulled from the slanted wellhead for the entire length of the wellbore. Two parallel horizontal wells were drilled through the producing formation, one above the other, at a vertical distance of 5 m.
The bi-wellhead design contributed significantly to production increase. Based on modeling with STARS package, various operating practices have been proposed. The flow management was achieved through change of the produced fluid and injected steam volumes, as well as change of steam injection and pump setting points. All these made it possible to form steam chamber uniformly, avoid steam breakthrough, and increase oil production with minimum steam-bitumen ratio. The average production rate of the experimental horizontal wells is ten times higher than that of the offset vertical wells. Current steam-bitumen ratio makes 3.5 t/t.
Fast and Efficient Sensitivity Calculation Using Adjoint Method for 3 Phase Field-Scale History Matching
Authors: Azmy Ramez , Daoud Ahmed M. , Fattah Khaled A. , Sayyouh M. H. 
Published: March 2009

Abstract
Adjoint method-based sensitivity for field-scale history matching with large number of parameters suffers from several limitations. First, the CPU time depends on the data points which are large for any brown fields of long history; second, it requires large memory to save the gridblock pressure and saturation per each time step used in the forward model. Third, it is computationally expensive as it requires solving the Adjoint system of equations backward in time per each forward time step which is usually of high magnitude in case of field scale applications of long history. Lastly, the solver used for solving the Adjoint system of equations needs to be efficient for large-scale applications.
We propose an efficient and fast approach for sensitivity calculation based on the Adjoint method to overcome much of the current limitations. First, we use a commercial finite difference simulator, ECLIPSE, as a forward model, which is general and can account for complex physical behavior that dominates most field applications. Second, the production data misfit is represented by a single generalized travel time misfit per well, thus effectively reducing the number of data points into one per well. Third, we solve the Adjoint system of equations backward in time in larger time step that is equivalent to the time of severe changes in pressure and saturation due to the changing of well conditions or introducing new infill wells rather than using the forward model time steps. This approach reduces the computational effort and memory allocated for the sensitivity calculation. Fourth, we use an iterative sparse matrix solver, LSQR, for solving the Adjoint system of equations which shows high stability for field-scale applications.
We demonstrate the power and utility of our approach using synthetic and pseudo field examples. The synthetic examples show the robustness and efficiency of our sensitivity calculation approach compared to the perturbation. The pseudo-field example has 10 years of production history with original gas cap and oil-water contact with strong aquifer support. Using well log data, core data, water-cut and gas-oil ratio history from producing wells; we characterize the permeability at each cell, thus demonstrating the feasibility of our approach for field applications.
Geosteering for Maximum Contact in Thin-Layer Well Placement
Authors: Al-Mutari Bander , Jumah Saud , Al-Ajmi Hussain , Ali Arshad , Saleh Khaled M. , Burman Kishore J. R. , Reeves David , Chemali Roland , Al Abri Hakim , Manrique Carlos , Hawkins Donald 
Published: March 2009

Abstract
The drive for rational exploitation of oil and gas resources has raised the bar on the accuracy of well placement. Thinly layered reservoirs represent a particular challenge as the opportunity to exit the reservoir is always present. This challenge is met using a suite of LWD instruments, including azimuthal deep resistivity, together with flexible forward modeling software. A new class of sensors sends to the surface in real time a variety of measurements and images with which to navigate. In the middle of the process is the geoscientist who must digest in real time the flow of information and synthesize it into clear and accurate instructions for the direction of the well.
When it comes to real-time information, the simple rule "More is better!" applies. However, a robust workflow is required to integrate and process the complex stream of data and to convert it immediately into actionable instructions. Because of the limited bandwidth of mud pulse telemetry, downhole data must first be integrated into higher level intelligence. For the wells in this study, resistivity measurements indicating an up or down direction for an approaching boundary were determined to be the most valuable information. In addition, a series of parameters named Geosignals gave early warning of approaching boundaries, allowing for timely and accurate corrections to the well path. A real time deep resistivity image was also sent to the surface to help visualize the geology several feet away from the wellbore.
Of the three wells discussed, the more recently drilled wells brought about significantly longer reservoir contact as geoscientists learned how best to use and interpret the azimuthal data. Similarly, experience gained from drilling problems encountered in earlier wells, coupled with close communications between operator and service provider, resulted in steadily improved drilling performance.
Integrated Reservoir Connectivity Study of Ahmadi Fractured Reservoir in Bahrain Field
Authors: AL-Muftah Ali , Kumar K , Murty C. R. K. , Lemaux Thierry , Ranjan Amit , Dejoussineau Ghislain , Bertrano Charles , Behira Hermann 
Published: March 2009

Abstract
This paper describes how the fracture model for Ahmadi was incorporated into a single and dual porosity simulation model. It highlights the approach and methodology that has been used for understanding the reservoir connectivity and its drive mechanism. In addition, the effect of dual porosity model in improving the initial history match of the reservoir performance and its recovery mechanism has been studied.
The two Ahmadi carbonate reservoirs in Bahrain Field (Aa and Ab) are thin, highly faulted and irregularly-fractured. The complexity of these reservoirs has prevented an efficient recovery with average production of wells to 15 Bopd. This has prompted a detailed integrated study to fully understand the recovery mechanism and to increase the wells' productivity.
A conceptual model has been developed for the reservoir connectivity of Ahmadi reservoirs by integrating static and dynamic data. This comprehensive study that integrates transient welltesting and production data with cores and image logs to map fracture network derived using seismic facies has resulted in improving the understanding of reservoir connectivity and flow mechanism. This was accomplished by building Discrete Fracture Model (DFN) that was tuned and validated using sector local well test models to match KH and pressure responses.
In order to reduce uncertainties in the model, different scenarios were built for different fracture intensity and aperture to derive appropriate parameters to pass to reservoir simulator for full field simulation. DFN model output was used in both single and dual porosity models to obtain production performance of the reservoirs.
Well Test Simulation using Orthogonal Collocation
Authors: AL-Muftah Ali E. 
Published: March 2009

Abstract
Welltesting is a flow of slightly compressible fluids in a porous media which is characterized by a set of nonlinear partial differential equations. Their solution is normally achieved analytically using Laplace transform or numerically through the use of numerical inverting methods of the Laplcace transform like Stehfest and Crump. Not all well test problems, however, are readily amenable to such treatment and an alternate approach like Orthogonal Collocation and Galerkin's methods are efficient and can be easily employed. Until now, the application of these techniques has been limited.
The primary objective of this paper is to investigate the feasibility of using Orthogonal Collocation on well test of a slightly compressible fluid in an ideal radial flow system. A well test simulation that treats the reservoir as a non-homogeneous, irregularly bounded system has been developed. Since this work was primarily concerned with the feasibility of Orthogonal Collocation simulation, no attempt was made to study a wide spectrum of well test problems. However, a few typical applications are presented and some of the results are compared with those derived from analytical and numerical inversion.
This study presents a new way to numerically simulate flow of slightly compressible fluid which is solved rigorously with wellbore storage and skin. This paper shows that the use of Orthogonal Collocation method is feasible and that, in many cases, it results in solutions that are more realistic than those resulted from numerical inversion of Laplace transform. There are, however, certain disadvantages. For example, oscillation of the pressure derivative which can be overcome by using Orthogonal Collocation on Finite Element (OCFE) in which programming effort are usually in excess of that required by a finite- difference or numerical Laplace inversion scheme. Even so, it is felt that the potential of the technique is sufficient justification for this work and for a continuing effort to apply it to well test simulation problems.