bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Application of Buckley-Leverett Displacement to Waterflooding in Non-Communicating Stratified Reservoirs
Authors: El-Khatib Noaman A. F. 
Published: December 2007

Abstract
A mathemathematical model is developed for performance prediction of waterflooding performance in stratified reservoirs using the Buckley-Leverett displacement mechanism. A modified definition of the mobility ratio is untroduced to account for the saturation variation behind the displacement front. Using this modified mobility ratio, the Dykstra-Parsons equations can be used to estimate the relative locations of the displacement fronts in different layers at the time of water breakthrough at a given layer. For layers after water breakthrough, expressions for the flow rate and water throughput are derived in terms of integral equations that are solved by iteration. The Buckley-Leverett and Welge tangent method is used to obtain the outlet and average saturations in each layer. These saturations are used to obtain the fractional oil recovery and water cut of each layer. Summation over all layers yields the performance of the total system. Expressions for the injectivity ratio are also derived.
Solutions for stratified systems with log normal permeability distribution were obtained and compared with those for the piston-like displacement (Dykstra-Parsons). The effects of viscosity ratio and the Dykstra-Parsons permeability variation coefficient (VDP) on the performance is investigated. The Introduction of pseudo relative permeability functions is discussed.
World's First Successful Openhole Logging Job with the Well Tractor Enables Faster and Cheaper Field Developments
Authors: Laws M. S. , Al Riyami A. N. S. 
Published: December 2007

Abstract
An openhole logging job was carried out in December 1999 using a Welltec Well Tractor in a 3.8km long, horizontal, water injector in the Lekhwair field in Oman. Two logging runs were carried out by Schlumberger, one of which reached the world record distance of 1550m in openhole (3012m along hole). Water flow log (WFL) and full bore spinner (FBS) data were measured and confirmed that injectivity is uniform along the length of this well, providing confidence in the current line drive, waterflood field development. This is the first time that quantitative logging data has been obtained from an openhole using the Well Tractor. This data, coupled with recent production data from other long wells in Lekhwair, provided the confidence to propose and drill extremely long horizontal wells (up to ~4km openhole length) in 2000, resulting in a significantly more cost effective and faster field development.
Steerable Motor with Integrated Adjustable Gauge Stabiliser Provides Improved Directional Drilling Performance in the Middle-East
Authors: Lawrence L. , Stymiest J. , Russell R. 
Published: December 2007

Abstract
In high angle wells, control of hole inclination becomes the main concern for directional drilling operations rather than azimuth control. The use of a conventional steerable system to control inclination can introduce such problems as increased torque and drag due to the doglegs created, and poor hole cleaning when in sliding mode. These problems can in turn limit the amount of horizontal section that can be drilled.
Adjustable gauge stabilisers have the ability to alter the gauge of the stabiliser without the requirement to pull out of hole. This type of stabiliser has been commonly used to assist in controlling inclination either in rotary assemblies or in steerable assemblies when run above a motor.
Although positioning the adjustable gauge stabiliser above the motor has been successful in many applications, there are situations where an alternative may be required. With the stabiliser positioned above the motor, it is relatively far from the bit and thus the effects of its gauge change are limited. This in turn results in the changes of inclination possible being relatively small. It may then be impossible to change the wellbore path quickly enough in geological steering applications. This can be addressed by placing the adjustable gauge stabiliser below the motor, but reliability of both tool and motor suffer. Stresses on the motor bearing assembly can be high enough to cause problems such as premature bearing and drive shaft failures.
By placing an adjustable gauge stabilser within the bearing housing of a steerable motor these problems have been overcome. The adjustable gauge stabiliser is therefore in a near-bit position. This means that changes in its gauge have the maximum effect on inclination. Stresses on the motor are also significantly reduced.
This adjustable gauge motor has been run in the Middle-East in long horizontal sections. It was seen to result in significant improvements in overall drilling rates when compared to conventional steerable motor runs. The subject of this paper is the design and development of the adjustable gauge motor system. Case histories will presented that demonstrate the improved performance that was achieved.
An Unconventional Approach for Drill-Bit Selection
Authors: Bilgesu H. I. , Al-Rashidi A. F. , Aminian K. , Ameri S. 
Published: December 2007

Abstract
In this study, a new method is presented to select rotary drilling bits in an oil or gas well. Planning a new oil or gas well requires selection of hardware components such as casings and bits. Additional information needed in the design and cost estimation of the new well is the performance of bits under varying operating conditions. The bit selection is an important task for the drilling engineer. The offset well information can provide valuable information. However, the data from the offset well contains a complex relationship between operational parameters, formation properties, drilling fluid properties and hydraulics, and bit design. The bits are selected based on the performance of similar bits in offset wells. Parameters affecting a bit performance have a complex pattern. The relationships between formation properties, drilling fluid characteristics, bit design, and operational parameters in these patterns are not easily understood.
In this approach, different variables such as bit type, rotary speed, weight on bit, pump circulation rate, drilled interval, and penetration rate are studied over a range of values. Two data sets from different fields located in the Middle East were used. Several neural networks were designed with three-layer back propagation architecture to select the bits for the next drilling interval. Additional neural networks were designed for predicting the cost of bits.
With the given data sets, these new models successfully predicted the bit types and cost-per-foot values for several fields. For the different data sets used in this study, the correlation coefficients for the predicted and field observed values ranged between 0.831 and 0.968.
Active Control of Stick-Slip Vibrations: The Role of Fully Coupled Dynamics
Authors: Christoforou Andreas P. , Yigit Ahmet S. 
Published: December 2007

Abstract
Oilwell drilling is often accompanied by self-excited stick-slip vibrations. This type of motion may also excite severe axial and lateral vibrations in the bottom hole assembly, causing damage to the equipment. This paper presents a fully coupled model for axial, bending and torsional vibrations, and an active control strategy for stick-slip vibrations. The proposed model includes the mutual dependence of these vibrations, as well as their related effects such as, bit/formation and drillstring/borehole wall interactions. The control strategy is based on optimal state feedback control designed to control the drillstring rotational motion. Simulation results are in close qualitative agreement with field observations regarding stick-slip vibrations. It is shown that the proposed control is effective in suppressing stick-slip vibrations once they are initiated. It is also demonstrated, that axial vibrations help in reducing stick-slip vibrations and the control effort. However, care must be taken in selecting a set of operating parameters to avoid transient instabilities in the axial and lateral motions.
A New Diagnostic Approach to Identify the Causes of Borehole Instability Problems in an Offshore Arabian Field
Authors: Mohiuddin M. A. , Awal M. R. , Abdulraheem A. , Khan K. 
Published: December 2007

Abstract
Many wellbore instability problems are being reported during development drilling at an offshore field in Saudi Arabia. It is a sandstone reservoir with shale intercalations at a depth of about 6000 ft. A few wells had to be abandoned because of stuck pipe and hole pack-off problems. Quite a number of wells had to be sidetracked, and drilled using oil-based mud (OBM).
The aim of this study is to identify the causes of the instability problems encountered in this field. The well plan, daily drilling report, well completion report, and various logs of each well are carefully studied. The frequency of instability problems, length reamed and the mud weight used are being analyzed with respect to wellbore azimuth, inclination and TVD. A computer program is developed using linear elasticity behavior of the rock material and the Mohr-Coulomb failure criterion. The model predicts the lower and the upper bounds of the mud weight that will prevent the borehole from compressive and tensile failure, respectively. Thus, we generate the stable mud weight window using rock mechanical and in-situ stress data pertaining to the problem wells where instabilities have occurred. Then we compare the mud weight used during drilling to the predicted mud weight window. Besides the Mohr-Coulomb failure criterion, we have used three modes of the Drucker-Prager criteria in order to compare the results.
An approach that combines statistical analysis and constitutive modeling to identify the causes of instability and predict safe mud weight window, is being used for the first time to the knowledge of authors. Some interesting results of the study indicating the possible causes of the wellbore instability are presented and discussed.
Management of Proppant and Fines Back Production in High-Rate Gas-Condensate Wells
Authors: Al-Zakwani Suleiman , Pongratz Reinhard , Fidan Erkan , Kaura Jiten Devender 
Published: December 2007

Abstract
Wellbore and formation cleanup must control proppant and fines backproduction, which can cause erosion and other damage to surface production equipment and lines. During wellbore and formation cleanup in the Barik and Saih Rawl fields, two approaches were used for managing proppant and fines backproduction. A sand-management system (SMS) consisting of a wellhead desander and a dual-pot filter unit was installed at the surface for separating solids from the fluid stream. During fracturing operations, a surface modification agent (SMA) was also used for preventing production of proppant and formation fines. The SMA allows the proppant pack to withstand three to five fold the critical velocity required for erosion. Laboratory tests indicate that the SMA improves vertical proppant distribution by hindering settling. In addition, when the SMA is used, fines resulting from proppant crushing or the formation itself are unlikely to migrate through the proppant pack and block pore throats.
Post-fracture cleanout indicated that (1) the proppant backproduction from the formation was minimized in two of the three treated wells, and (2) solids were likely controlled within the fracture. Both conditions reduced cleanout time. Productivity was also believed to be enhanced, but well-test data was unavailable for proving this theory.
This paper describes an integrated method for managing proppant flowback. This method combines solids handling in the reservoir and at the surface.
EMpower: New Reservoir Simulation System
Authors: Beckner B. L. , Hutfilz J. M. , Ray M. B. , Tomich J. F. 
Published: December 2007

Abstract
During the late 1990's, Exxon and Mobil had each independently developed next-generation reservoir simulation systems. Both next-generation systems embodied a substantial number of step-out simulation technologies, which were extremely complementary. ExxonMobil moved aggressively to combine the best of both companies' technologies into one industry-leading simulation system called EMpower TM. This new simulation system is now being used to actively manage ExxonMobil’s global resource base. Key features of this industry-leading simulator are described in this paper.
The new simulator employs unstructured grids to more accurately model complex geologic features, near-wellbore flow, and aquifer support. Algorithms for optimal layering and flow-based scale-up on unstructured grids are tightly integrated in the EMpower system. The computations are performed within the unstructured grid fabric. Interactive simulation ties together the geologic and reservoir simulation models with production data yielding high-confidence forecasts of future performance.
Emphasis is on minimizing the overall turnaround time between formulation of the simulation problem and generation of results. A comprehensive graphical user interface provides reservoir engineers and geoscientists of all skill levels with easy access to reservoir simulation. The user interface is designed to facilitate the full range of simulation problems-- from quick screening studies to large, complex field models. The geoscience and reservoir engineer communicates to the executing simulation through the user interface, thereby allowing simulation progress/results to be monitored, paused, terminated, and/or restarted on command. Results are viewed within the user interface using spreadsheets, charts, or full 3D visualization.
The object-oriented design of the new simulator is very flexible. The reservoir flow model is tightly integrated with the well and surface facility models for accurate, smoothly running simulations. Execution of complex well management strategies is specified in an intuitive, graphical format. For added efficiency, the simulator also is designed to take advantage of computing hardware that utilizes multiple parallel processors.
The capabilities of this next-generation simulation system are demonstrated through a field study involving complex geologic features (e.g. non-vertical faults and stratigraphic pinchouts) and multiple reservoirs connected to a common production infrastructure.
Field Application of Stopcocking for Gas Coning Control and it's Optimisation
Authors: Dutta Bapan K. , Ali Mohamed Yaseen 
Published: December 2007

Abstract
Gas breakthrough because of coning is very common in Bahrain field particularly in naturally flowing oil wells. It escalates gas flow and reduces oil rate as cone reaches the perforations. Consequently, wells gas out and recovery of oil below the GOC becomes very difficult. Flow stopcocking with time cycle control has been introduced to restrain gas cone breakthrough as conventional surface bean reduction approach proved ineffective. Case studies show that stopcocking enables a better control on draw down, prevents cone breakthrough and improves oil recovery. In addition, wellhead pressure data reveals that smaller surface bean causes increased liquid fall back and reduces stopcock flow efficiency. The case studies brought to light a very important fact of liquid reentry into formation and consequent slug height loss. Study of borehole flow dynamics indicates liquid diversion back and forth annulus and tubing during shut in cycle. A mechanistic model has been developed to help understand the flow behavior and optimize the system operation. Simulation shows that the performance of downhole flow control plays very important role in liquid accumulation inside tubing and annulus. Moreover, completion geometry has significant role in gas accumulation, fluid segregation and slug height build up. To optimize the stopcocking flow, a completion design that alleviates the drawbacks of the typical configuration has been discussed.
Optimization Strategies for Hydraulic Fractures in High Permeability Reservoirs
Authors: Aggour Tamir 
Published: December 2007

Abstract
High permeability fracturing, commonly referred to as a frac&pack treatment, is becoming an increasingly popular completion option for both well productivity improvement and sand control in poorly consolidated formations. This paper presents an efficient and effective economic optimization scheme for hydraulic fractures in high permeability formations. The optimization scheme incorporates global optimization algorithms that simultaneously optimize all of the treatment parameters, including fracture dimensions, while accounting for the required constraints. The scheme is not dependent on specific fracture geometry or production prediction models, and the optimization algorithms are more efficient than the approaches currently used. Parametric studies were conducted, and some general trends and guidelines were observed. Field data from frac&pack treatments were reviewed and compared to the findings of this research. A review of field data indicates that the results of our optimization scheme are realistic, confirming some of the conclusions derived from the parametric studies and suggesting that this approach can be a useful tool for designing fracture treatments in high permeability reservoirs.
Improved Near-Well Reservoir Characterisation of a Complex Gas Condensate Reservoir in Saudi Arabia by Integrating Core, Log, Seismic and Extended Well Test Data
Authors: Al-Qahtani Mohammed Y. , Buhidma Ismail M. 
Published: December 2007

Abstract
The Jauf reservoir is a deep sequence of thin sand/shale beds with a large degree of variation in permeability and porosity saturated with rich gas. 3-D seismic interpretation indicates high degree of faulting and reservoir fluid variations indicate compartmentalization.
This paper presents the results of three pressure drawdown and buildup tests from a Jauf well, in which PLT survey as part of the second test indicated non-uniform flow profile reflecting the contrast in permeability between the various sand layers. A number of interpretation models were investigated using data from the first and second tests. The tests exhibit boundary effects that were interpreted to represent limited extension of the high permeability layer but not conclusive for the lower permeability layers. The third test was designed with long flow and shut-in periods, based on the second test interpretation, to confirm reservoir layering and compartmentalization.
The analysis integrates pressure transient, PLT, seismic and core data and demonstrates the importance of knowing the flow profile and designing test duration in order to get a more realistic interpretation. The core data confirmed that the non-uniform profile was not the result of damage but in fact reflects variation in permeability, which was not clear from openhole logs.
The interpretation of the third test indicates two main reservoir systems, the first is high permeability closed system of finite extent and the second is very tight infinite acting system. The interpretation also shows that significant portion of the gas in place in this reservoir is in rock of lower permeability than initially thought. The implications of this finding on well completion and productivity enhancement options are also presented.
A New Technique and Field Application for Determining Reservoir Characteristics from Well Performance Data
Authors: Al Qahtani Abdullah M. 
Published: December 2007

Abstract
Traditionally, transient testing is used to determine important reservoir properties, such as reservoir permeability, formation damage (skin) and reservoir boundaries. The data during transient testing are acquired by placing a pressure gauge downhole close to the reservoir. This requires a wireline unit and a vessel for offshore wells. Also, it requires the well to be shut in after producing for an extended time at a stable rate. Hence, It is difficult to do frequent transient testing for wells experiencing a drop in their productivity/injectivity due to logistics & economic constraints. In addition to the economic considerations in running such a test, the process is time consuming in acquiring the data and analyzing the results.
This paper presents a new approach that uses historical surface performance data at surface, acquired during production mode, to estimate reservoir properties. This approach is based on establishing the trend of the performance of a well from production data. From that data, a regression analysis is used to obtain a pseudo productivity index that is function of rate. That parameter is corrected to the actual productivity index of the well using the limit function at shut-in condition. Newton-Raphson approach is then used to estimate the average reservoir permeability and total skin using from the actual productivity index based on pseudo-steady state equation. Classical methods can be then used to calculate the breakdown of the total skin. The application of this approach in the field revealed that it could give satisfactorily results that compare favorably with transient test results. It introduces a new and quick measure of evaluating well performance and completion efficiency. It can also show the variation of the IPR of a well, due to increased gas saturation, through the production life as previously presented by Muskat. This approach uses the available abundant data that is intended to serve other objective with computer applications to achieve the objective of transient testing. It can be utilized in cases where it is difficult to conduct transient testing.
Evaluation of Super-K Wells Performance Using Fluid Flow Index in Ghawar Field
Authors: Al-Ajmi Fahad A. , Al-Shahri Ali M. , Sengul Mustafa M. , Phelps Robert 
Published: December 2007

Abstract
Reservoir management engineers at Aramco are fortunate to have a wealth of information about their reservoirs in the corporate database. However, this wealth of information comes with a challenge of analyzing this immense collection of data and utilizing this information for decision-making. In this study we used data mining process to explore our database and evaluate the performance of wells in a study area of Ghawar field. The performance of more than 450 wells was then related to the super-k existence from flowmeter data.
The existence of super-k layer was believed to cause premature water breakthrough and hence poor vertical sweep. The objective of the study was to answer the following question: Will producing a super-k well without isolating the super-k layer result in less cumulative oil production after water breakthrough?
In this paper we developed a methodology to identify and quantify super-k while avoiding the pitfall of black or white (i.e. super-k or non super-k well). Super-k quantification was accomplished by deriving Fluid Flow Index from flowmeter surveys. The next challenge was to come up with a consistence measure of well performance so that all the wells can be compared on the same basis. This challenge was overcome by introducing the new definition of cumulative oil production and average oil rate after water breakthrough.
In this paper we developed correlations to predict the performance of future wells to be drilled in the area. The study indicated that there was a positive correlation between super-k and high average rate after water breakthrough. Also, it was found that anomalous flood front encroachment in the east flank of the field is unrelated to the super-k. The study showed that reservoir performance is controlled by the interaction between Faults/Fractures and Super-k layers.
The results of this study created a paradigm shift in perceiving super-k layers in Ghawar. Field data showed an improved well performance by perforating isolated super-k layers. Moreover, the derived Fluid Flow index was used in building an enhanced and more realistic model for the field.