bluuebunny/crossref_metadata_2025 huggingface dataset:
Assessment of Residual Oil Saturation in a Large Carbonate Reservoir
Authors: Pham Tony R. , Al-Shahri Ali M.
Published: December 2007

This paper discusses the assessment of Residual Oil Saturation (ROS) in a large, prolific, water flood carbonate Arab-D reservoir in the Middle East. The determination of Residual Oil Saturation is very important since it is a crucial step in the accurate evaluation of sweep efficiency, reservoir management strategy, EOR feasibility, and oil recovery factors. Recovery in a water flood reservoir is the function of economic limit, and displacement and sweep efficiency (in both areal and vertical direction).

The reservoir carbonates were grouped into different reservoir classifications from cores extracted from nearly 500 wells. Numerous laboratory water flood tests using centrifuge, unsteady state and steady state methods were performed on these cores. The results from these laboratory tests were screened, tabulated and evaluated against one another for different rock types as well as against the field test results. The advantages and disadvantages of each laboratory test method are also highlighted. The paper will discuss which type of laboratory tests are required to properly model the reservoir sweep mechanism, how the reservoir rock types could be classified, and how reservoir simulation models could be used to arrive at a credible ROS estimate for the whole reservoir.
The Application of Buckley-Leverett Displacement to Waterflooding in Non-Communicating Stratified Reservoirs
Authors: El-Khatib Noaman A. F.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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

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.
Single Medium Simulation of Reservoirs with Conductive Faults and Fractures
Authors: van Lingen Paul , Sengul Mustafa , Daniel Jean-Marc , Cosentino Luca
Published: December 2007

This paper describes a technique to incorporate conductive faults and -fractures in a reservoir simulation model. The technique is appropriate for reservoirs with significant primary matrix productivity, and a large spacing between fractures (in the order of tens of meters). The single porosity (one grid) formulation is applied. Any fracture geometry can be represented accurately without grid modifications. The key elements of the approach are pseudo relative permeability curves for grid bocks containing fractures. These curves are determined through an analytical procedure, based on the local fracture and matrix properties. The method is applied successfully to a Middle East carbonate reservoir.
Investigation of H2S Migration In Marjan Complex
Authors: Al-Eid Mohammad I. , Kokal Sunil L. , Carrigan William J. , Al-Dubaisi Jaffar M. , Halpern Henry I. , Al-Juraid Jamal I.
Published: December 2007

Marjan complex is a large offshore oil field located in the Arabian Gulf and is composed of four fields: Marjan 1, Marjan 2, Marjan 3 and Marjan 4. Currently production in the complex is limited to the Khafji reservoir. For several years, it was known that the H2S concentration in the Khafji reservoir varied across the complex. A comprehensive study was initiated to map the concentration profile of H2S across the complex and to address the migration of H2S within it. This included area-wide well-stream H2S measurement and geochemical fingerprinting of Marjan oils. For the first time, the concentrations of H2S were mapped across the complex. The southern and southwestern wells show relatively high concentrations of H2S, and the northern wells show no, or negligible amounts of H2S (less than 10 ppm). The migration of H2S into the northern part of the field has serious implications because the crude handling facilities, or the gas-oil separation plant (GOSP), were designed for sweet crude processing. If migration is proven, the facilities in the northern part of the field need to be upgraded to handle sour crude.

The results of this study indicate that there is a ‘hot’ spot of high H2S located in the southwestern part of the complex. There is a significant H2S gradient across the Marjan complex with H2S decreasing from the southwest to the northeast. H2S concentration profiles with time also indicate that there is an increase in H2S concentration with time in the hot spot. The data negate the possibility of H2S generation in the Khafji reservoir from either sulfate reducing bacteria (SRB) or thermochemical sulfate reduction (TSR). Therefore, it is suggested that the H2S is migrating into the Khafji reservoir from somewhere else, probably from the Ratawi or other, deeper reservoirs.

The geochemical analyses show that the hydrocarbon composition is very uniform across the complex, and there is no evidence for barriers to fluid flow within the Khafji reservoir. It is proposed that the lateral migration of H2S within the reservoir is arrested due to the presence of H2S-scavenging iron minerals. Two hypotheses are proposed for the migration of H2S into the Khafji reservoir from the Ratawi reservoir: (a) through inter-reservoir faults, or (b) through channeling leaks behind well casings. These two hypotheses are discussed in the paper.
Optimization of Gas Condensate Reservoir Development by Coupling Reservoir Modeling and Hydraulic Fracturing Design
Authors: Aly A. M. , El-Banbi A. H. , Holditch S. A. , Wahdan M. , Salah N. , Aly N. M. , Boerrigter P.
Published: December 2007

This paper presents the results of a study that included both compositional reservoir simulation and hydraulic fracture modeling. These models were used to optimize the production and recovery from a rich gas condensate reservoir.

The study illustrates the upside potential of creating propped hydraulic fractures in a gas condensate reservoir. The reservoir is a multi-layered, low permeability, rich gas condensate formation. We performed this study to investigate the possibility of enhancing productivity from the reservoir and to increase gas recovery.

Several wells existed in the field before the fracture treatment campaign was initiated. In this paper, we highlight modeling of three types of wells: vertical wells, vertical wells with multiple fractures, and horizontal wells. In all cases, the effect of condensate dropout around the well and/or the fracture is investigated. The effect of improving the relative permeability due to high velocity around wells is also discussed.

The successful integration of reservoir and fracture modeling resulted in 40% cost savings when compared to the original development plan.
The Obaiyed Gas Recovery Project - A Fully Integrated Study
Authors: Bouman M. , Koopman A. , Ibrahim N. S.
Published: December 2007

A fully integrated study was required to solve the puzzle of the rapidly declining reservoir pressures in the Obaiyed Field. A more regional sedimentological and structural approach formed the basis for a new reservoir model. Consequently the field is now subdivided in a number of discrete blocks, each with its own static and dynamic parameters to predict reservoir properties.
Maximising Value from a Complex Fluvial Reservoir in South Oman: Results from an Integrated PE Study of the Zauliyah Field
Authors: Otiocha James O. , Al-Bulushi Abdulwahab , Al-Harthy Khalfan S.
Published: December 2007

An integrated PE review of Zauliyah field was necessitated by the poor field performance under depletion drive. The review resulted in a new reservoir model conducive to a water injection scheme. Consequently, the field is currently being re-developed by waterflooding. This project phase is accelerated, and will develop 4.0 million m3 of reserves at an average unit technical cost of less than $2/bbl.

General

The Zauliyah field is a NW-SE trending anticlinal structure (Figure 1) that contains light oil (44 API) in five stacked reservoir units of the Permian Upper and Middle Gharif fluvial sandstones. A 25-meter thick shale layer separates the Upper Gharif [UG] reservoirs (20-23% porosity, 8-20% net/gross) from the Middle Gharif [MG] reservoirs (19-23% porosity, 25-51% net/gross).

Discovered in 1981 and with a booked STOIIP of 56 mln m3, the field came on stream in 1984. 14 vertical wells have been drilled (ZL-11 was cored, while ZL-12 has FMI data). The initial development by depletion drive recovered only 6% of the STOIIP before reservoir pressure in most parts of the reservoir units declined to below bubble point. A waterflood programme was considered but could not be embarked upon for risk that the reservoirs were isolated and highly compartmentalised (Figure 2). Therefore, the field continued to produce by depletion drive, but most wells had to be closed-in intermittently due to excessive gas production and flaring. Under these circumstances, the development of booked reserves was not economically attractive, making reserves de-booking imminent at the time. However, this view changed following a multi-disciplinary PE study and water injection pilot schemes. It is now planned to book additional reserves in 2001, and the re-development of the Zauliyah field by water injection has been put on fast track.
The e-Field -- (The Electric Oilfield)
Authors: Jack Ian
Published: December 2007

Time lapse seismic ("4D") shows an impressive growth curve. Recent work on multi-component data ("4C") also shows good potential for the future. These technologies offer ways in which we could improve our reservoir management. For time lapse work, new techniques should allow us to improve the threshold for detection of the seismic effects of pressure and fluid changes. Furthermore, these techniques will allow re-shoots at minimal cost, on a schedule driven by the needs of the reservoir engineers. For multi-component technology, the benefits of imaging with shear waves through gas-filled sediments are already well demonstrated. However, gas clouds are only one of several problems which can be impacted -- there are many potential benefits to be had from this technology, especially in the marine environment.

It seems very likely that these two major new technologies will merge. A strong enabler would be the availability of affordable emplaceable seismic detector systems. For example, if a system could be installed for not much more than a conventional towed-cable seismic survey, it would be irresistible and would open up an entirely new market. We will then have the beginnings of what we might call an "electric oilfield" or "e-field". Our vision is that by combining the imaging techniques above with continuously available engineering data such as pressure, temperature, and saturation coming from emplaced downhole instrumentation, we will achieve a step improvement in reservoir surveillance and thus allow our engineers to improve the management of their reservoirs. The challenges will be to speed the implementation of these systems and to integrate the data successfully, because historically new technologies take years to achieve acceptance. "Cost" and "value" have to be understood and reconciled, and this takes time.
Integrated Development and Early Production Scheme for the Burgan Reservoir in the Soroosh and Nowrooz Fields Offshore Iran
Authors: Denby P. , de Groot H. I. , Guit F. , Willet A.
Published: December 2007

The Soroosh and Nowrooz fields were offered to the industry by NIOC, under the ‘buy-back’ arrangement, in July 1998. In November 1999 a service contract for an integrated development of both fields was signed between NIOC and Shell. The service contract calls for an early oil production system on Soroosh, producing 60,000 bopd of oil within 24 months and 190,000 bopd oil production (100,000 bopd from Soroosh and 90,000 bopd from Nowrooz) from permanent production facilities within 45 months of the signing date.

The Soroosh Field is located some 80 km WSW of Kharg Island (figure 1). The field was discovered in 1962 by IPAC, the former operator and to date fourteen wells have been drilled. Cumulative production in 1979, when the field was shut-in, totaled just over 86 million bbl from the Burgan B mainly from the crest with two wells showing signs of water breakthrough. Crude analyses suggest the presence of a density gradient over the oil column in the main Burgan B reservoir at depths of 2,131 mss down to an oil-water-contact at 2,272 mss. High viscosities over the base of the oil column possibly reduce aquifer support. Definition of fluid property distribution and prediction of the oil-water displacement process present the main challenges.

The Nowrooz Field is located some 80 km WNW of Kharg Island. Agip, the former operator, discovered the field in 1966 and to date fifteen wells have been drilled. Historic production, also from the Burgan B (or Nahr Umr Sand as it was previously referred to), totals around 100 million bbl, with one wet producer. The crest of the structure is at 2,230 mss with an OWC at around 2,337 mss. The structure is heavily faulted along the crest, however, pressure support has not been an issue and a volumetrically large flank aquifer is expected to provide sufficient reservoir drive. Prediction of fault patterns and reservoir development presents the main challenge to the subsurface development.

In the project to date, 3D seismic data acquisition, geophysical and geotechnical surveys have been carried out. Seismic processing and interpretation was ongoing at the time of writing this paper.

This paper describes remaining development uncertainties, and how these will be addressed during the forthcoming production drilling and early production phase.
The Challenges and Way Forward of Horizontal Dual Lateral Wells in Fahud Matrix Reservoir
Authors: Al-Khodhori Shaikhan
Published: December 2007

The Fahud field, on stream since 1967, is being the largest field in Oman in term of STOIIP 1×10(9) m3. This great carbonate field, initially produced by natural depletion, followed by gas injection in 1968, water flooding drive in 1972 and is now being produced by gas-oil gravity drainage process (GOGD) since 1984. The field once thought to be completely covered with fractured reservoir, hence only GOGD development with crestal gas injection for voidage replacement has recently being also developed by water flooding in Shuiaba and Natih matrix reservoir.

The dual lateral completion aims to maximize the productivity from relatively low permeability matrix units. The two laterals are normally completed barefoot (Level 2 multilateral) with a single selective 3 ½" gas lift completion. As completion stays simple and cost effective, lateral re-entry remains one of the main challenge. Different technologies have been applied to address various completion challenges in these dual laterals, with various degrees of success. For instance a pre-milled secure window at the junction to allow upper lateral re-entry has been applied with technical success but hindered 7" liner cementation. Other areas that have been atried in dual laterals are improving acid stimulation techniques, lifting optimization, improving well design to overcome hole problem, improve liner cementation, producing and monitoring each lateral, etc. at different degrees of success.

This paper is intended to cover all these major challenges facing Fahud horizontal dual lateral wells matrix reservoirs, technologies applied and their outcomes (success and failures), and foreseen future completion issues in term of subsurface characteristics uncertainties and way forward. Given such a large STOOIP, and the fact that GOGD process has slow and low recovery factor, maximizing these low permeability matrix units is essential for the field production.
Field Pilot Test of Thermal Stimulation of Rubble Reservoir Using Down Hole Induction Heaters
Authors: Sivakumar V. C. Babu
Published: December 2007

Production of the viscous heavy oil from the shallow Rubble reservoir (about 1500-1600’) in the Bahrain field has been a challenge given its low gravity (12-18° API) and high viscosity (350 cps at 40° C). It was planned to carry out a trial test of thermally stimulating the formation to improve the production rates from this reservoir using a downhole heater. Since the greatest pressure drop in a producing well is always near the well bore application of heat at the well bore to reduce the oil viscosity can result in dramatic increases in oil production. The trial test showed an increase in oil production from < 10 bopd to about 70 bopd initially and later stabilized at about 40 bopd. Even a modest increase in downhole temperature was seen to have a significant effect on both the water cuts and production rates.

Of the various types of downhole heaters available it was chosen to install an induction type of heater in view of the various inherent advantages. Primarily, these heaters could be installed in wells with no special completion requirements. The Inductor tool assembly utilizes the electrical energy to inductively heat the reservoir through the Ferro-magnetic casing. Efficient three-phase power delivery through an ESP cable using high voltage and low current minimizes resistive power losses and as much as 80-85% of the delivered power can be converted into heat.

The paper deals with the trial installation, operation problems encountered and the production performance of the well on trial. Based on the success of the pilot additional installations are being planned for trials in two more wells with heavier and more viscous oil quality.
Producing the Ultimate from the Saih Rawl Shuaiba Reservoir
Authors: Senger Jens-Christian , Al-Harthi Nasser R. , Avest Dick ter , al-Bahry Alia , Bigno Yann
Published: December 2007

Horizontal drilling of multilateral wells within the last five years has rapidly developed the Saih Rawl Shuaiba reservoir. These wells consist of up to 7 branches, and expose more than 10 km openhole of reservoir per well. Current production of the reservoir is around 8,000 m3/d of oil with an average watercut of 75%. A "produce-the-ultimate"-initiative was followed to systematically analyze, debottleneck and optimize every detail of the production chain: from water injection manifold, water injectors, to oil producers with ESP, including the waterflood efficiency. This has resulted in a range of optimization activities such as ESP changeout, flowline looping, water injector tubing resizing, automation of chokes and an improved water injection distribution system. Initial gains from part of these activities amount to more than 1,000 m3 of oil per day within the first six months.
Influences of Asphaltene Deposition on Rock/Fluid Properties of Low Permeability Carbonate Reservoirs
Authors: Shedid Shedid A.
Published: December 2007

Asphaltene deposition has profound effects on oil flow through porous medium. The investigation of the influences of asphaltene precipitation on carbonate reservoir rocks has minor interests in comparison to studies investigated sandstones ones. Therefore, this study is undertaken to provide accurate insights, especially for carbonate reservoirs of low permeability.

In this study, two groups of experiments are undertaken. The first experimental group investigates effects of asphaltene precipitation on (a) petrophysical properties of carbonate rocks, including absolute permeability, effective porosity, and hydraulic radius, and (b) on oil-water relative permeability and water flooding performance. The second group searches for the effects of asphaltene precipitation on capillary pressure and pore size distribution of low permeability carbonate reservoirs. Conducted experiments are achieved using actual reservoir liquids of crude oil and brine, flowing through actual carbonate cores under similar reservoir conditions of temperature and pressure.

The results indicated that asphaltene precipitation damages absolute permeability and hydraulic radius drastically, reduces effective porosity, and improves relative permeability of water for different asphaltene contents of crude oil flowing through carbonate reservoirs. In addition, oil reservoirs of high asphaltene content have shown higher values of irreducible water saturation than that ones of low asphaltene content in their crude oils. Precipitation of asphaltene in carbonate rock causes changes in the position of capillary pressure at high mobile oil saturation and reduces values resulted for pore size distribution curves, especially for small pore radii carrying crude’s of high asphaltene content.

Neglecting the proven influences of asphaltene precipitation may lead to erroneous description of carbonate reservoirs. Therefore, analysis of petrophysical properties and pore size distribution of carbonate reservoirs has to be updated during the extended life of oil reservoir and based upon accurate values of asphaltene content of the flowing crude oils.

Applications of the attained results of this study are expected to provide real improvement in reservoir description, more reliable estimation of oil reserves, accurate predicted values of reservoir rock damage, and also better descriptive functions for future reservoir simulation studies.
Prediction of Oil PVT Properties Using Neural Networks
Authors: Osman E. A. , Abdel-Wahhab O. A. , Al-Marhoun M. A.
Published: December 2007

Reservoir fluid properties are very important in reservoir engineering computations such as material balance calculations, well test analysis, reserve estimates, and numerical reservoir simulations. Ideally, these properties should be obtained from actual measurements. Quite often, however, these measurements are either not available, or very costly to obtain. In such cases, empirically derived correlations are used to predict the needed properties. All computations, therefore, will depend on the accuracy of the correlations used for predicting the fluid properties.

This study presents Artificial Neural Networks (ANN) model for predicting the formation volume factor at the bubble point pressure. The model is developed using 803 published data from the Middle East, Malaysia, Colombia, and Gulf of Mexico fields. One-half of the data was used to train the ANN models, one quarter to cross-validate the relationships established during the training process and the remaining one quarter to test the models to evaluate their accuracy and trend stability. The results show that the developed model provides better predictions and higher accuracy than the published empirical correlations. The present model provides predictions of the formation volume factor at the bubble point pressure with an absolute average percent error of 1.789%, a standard deviation of 2.2053% and correlation coefficient of 0.988. Trend tests were performed to check the behavior of the predicted values of Bob for any change in reservoir temperature, Gas Oil Ratio (GOR), gas gravity and oil gravity. The trends were found to obey the physical laws.
Scale Inhibitor Injection Via the Gas Lift System in High Temperature Block 3 Fields in Angola
Authors: Poggesi Guido , Hurtevent Christian , Brazy Jean Louis
Published: December 2007

When scale problems occur into the tubings, without hardly affecting the well productivity, it can be interesting to find new downhole injection means, representing an alternative to classical squeezes.

On some wells of block 3 in Angola, the squeezes turned out difficult because of the reservoir heterogeneity and temperature (164°C). The reservoir being dolomitic most of the inhibitors show a strong incompatibility and precipitate when injected. The operator of these fields preferred to turn to an inhibitor injection via the gas lift system.

This injection is made possible, because scales, made by calcium carbonate and barium sulphate, do not affect the well bottom but only the tubing. The gas lift valves are located under the area where scale begins to form and the inhibitor injection through the gas lift system permits the prevention of scale precipitation into the wells without having to perform squeeze treatments.

Injection via the gas lift began with standard inhibitors dissolved in water to which VPD (vapor pressure depressants) were added.

In spite of the presence of VPD, water evaporation caused the formation of gums and a rapid clogging of the gas-lift valves. Therefore a solid scale inhibitor was used and diluted in solvents with a very high boiling point, so that it would not evaporate at well temperature, i.e. 164 °C.

The case history we are presenting, describes the design of the scale inhibitor, the injection and the follow-up which have been carried out in Angola on 11 wells in Block 3 fields.