bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Geomechanics to Optimize Field Development Strategy of Deep Gas Reservoirs in Saudi Arabia
Authors: Ahmed Mahbub S. , Finkbeiner Thomas , Kannan Adnan A. 
Published: December 2007

Abstract
Saudi Aramco has embarked on drilling long horizontals and maximum reservoir contact (MRC) wells in the deep gas reservoirs. Regional stress field is playing an important role in predicting wellbore stability and future production performance of these wells. To successfully drill and produce these long horizontal wells a detailed geomechanics study and its results needed to be incorporated in the decision tree. Reservoir Management was keen to find the optimum azimuthal direction to place horizontal wells, which will minimize the risk of hole breakouts, optimize drilling mud weights, and ensure sustainable production under depletion mode. A study was undertaken to study the effect of geomechanics on drilling and production of these gas wells. Drilling and production histories along with laboratory measurements were incorporated in the study. The study concluded that horizontal wells should be drilled parallel to the locally derived maximum principal stress (SHmax) azimuth to maximize borehole stability and minimize required mud weights during drilling and production. To date a substantial number of wells have been drilled in the field following the recommended drilling direction that would ensure minimum damage to the reservoir and well's productivity.
The objective of the paper is to illustrate methodologies employed to find the optimum drilling direction causing the least damage to the reservoir and discuss implementation of its findings in the field development.
Successful Water Shut-off in Open Hole Horizontal Well Using Inflatables
Authors: Al-Shahrani Faisal F. , Baluch Zulfiqar A. , Al-Otaibi Nashi M. , Sarfraz Tashfeen 
Published: December 2007

Abstract
Water shut-off treatment (WSOT) using through tubing bridge plug (TTBP) in open hole completion has been employed for the first time in a dead horizontal well in one of the onshore fields in Saudi Arabia. It was successfully applied by setting an inflatable bridge plug (TTBP) in the 6 1/8" open hole at 10,600 ft at 88 ° and capping it with cement and gel using coiled tubing (CT).
Historically, it has been difficult, if not possible, to perform mechanical water shut-off in open horizontal well, as inflatables are quite sensitive to be set in open hole. This paper shows that this type of water shut-off in open hole is feasilble and very effective. This will open the doors to apply similar techniques to liven dead horizontal wells in other fields.
Laboratory Studies of MEOR in Micromodel as a Fractured System
Authors: Nourani M. , Panahi H. , Biria D. , Azad R. Roosta , Haghighi M. , Mohebbi A. 
Published: December 2007

Abstract
Microbial enhanced oil recovery (MEOR) is receiving renewed interest worldwide in recent years as a viable method while not damaging the reservoir is proven to be remarkably effective, however to some extent costly. This method is based on microorganisms’ activities to reduce residual oil of reservoirs, which is dependent on behavior of inherent microorganisms or injection of bioproduct of external microorganisms.
In this work, five bacterial species were taken from MIS crude oil that is one of the aging Persian fractured reservoirs. These microorganisms are substantially strong in increasing oil recovery especially by reducing IFT and other MEOR mechanisms such as change of wettability of rock at the favorable condition for the activities of these bacteria observed within the temperature range of 50°C to 90°C at the atmospheric pressure.
Two series of visualization experiments were carried out to examine the behavior of microbial enhanced oil recovery in micromodels designed to resemble the fractured system: static and dynamic. In the static one, carbonate rock-glass micromodel is used to simulate the reservoir conditions and the latter is performed by a glass micromodel which has a fracture with 45 degree inclination. The image processing methodology is used to determine the recovery achieved by MEOR in the micromodel made of glass.
Lithofacies, Sand-Bodies Geometry and Depositional Setting of the Datta Formation in Surghar Range, North Pakistan
Authors: Obaid Shams , Qureshi Amjad W. , Abbasi Iftikhar A. 
Published: December 2007

ABSTRACT
Thick Mesozoic sedimentary racks are exposed overa wide area in the Lower and Upper Indus Basin of Pakistan, particularly along the western margin of the Indian Plate. The Mesozoic sequence is generally comprised of clastic facies in the lower part, carbonate facies dominate in the upper part. In the Surghar Range the Datta Formation represents the lower part of the early Jurassic sequence. The formation is comprised dominantly of clastic facies with carbonate interbeds at places. The Datta Formation of early Jurassic was measured and described in the Chichali and Pannu gorge, Surghar Range. The total thickness of Datta sediments at Chichali section is 161m while thickness of the Pannu section is 225m. Sections were measured for sedimentological studies and sand bodies were classified accordingly. On the basis of lithological variation and sedimentary structures eight lithofacies have been recognized. These lithofacies are; LF 8: Clay lithofacies, LF 7: Cross bedded sandstone lithofacies, LF 6: Siltstone lithofacies, LF 5: Interbedded limestone and shale lithofacies, LF 4: Sandstone with intercalations of clay lithofacies, LF 3: Carbonaceous shale lithofacies, LF 2: Channelized sandstone lithofacies, LF 1: Interbedded sandstone and shale lithofacies.
Three kinds of sand bodies were identified, these are mostly multistorey channels but some simple ribbons as well as sheets are also present. Fossils identified are gastropods and pelecypodes.
After collecting and interpreting the data acquired from the measured sections and sandstone bodies' geometry analysis, it is interpreted that the Datta Formation was deposited along the delta plain and delta front setting by a fluvial-wave dominated delta. Continental, transitional to oceanic conditions prevailed at the time of deposition of the Datta Formation and all the facies show prograding deltaic setting. Cross beds interpretation indicates east to west flowing channels.
Addressing Some of the Unique Challenges of Drillstem Tests in Tight Gas Reservoirs
Authors: Akram Agha Hassan , Khan Mohammed Riaz 
Published: December 2007

ABSTRACT
An innovation in the methodology of conducting drillstem tests (DSTs) in tight gas reservoirs is presented, along with a simplification in the interpretation of the data obtained. DSTs in tight gas reservoirs are a problem because the flow rates are often too low to be measured by conventional equipment. In these cases a normal flowing and buildup test should be followed by a closed chamber test to produce usable estimates of flow rates at various times during the preceding normal flowing and buildup test. This estimated flow rate can then be used to interpret the buildup after the flow testing, which is produced by shutting the downhole valve.
In the interpretation of DST data from a tight gas reservoir, factors such as the following have to be considered: 1) large variation of gas properties resulting from the large pressure range involved1,2; 2) flow rate duration that can be many times shorter than the buildup period3,4,5,6; 3) varying flow rate during the flowing part of the test; and 4) impact of boundaries and heterogeneities.
We show that a simple interpretation approach with constant flow rates and pseudo-pressure yields results that are within the intrinsic accuracy limits expected from such a test.
The benefits to the field interpreter of using the methods presented are 1) operational flexibility: if the well flows strongly enough the rate may be measured at surface; if it does not, a closed chamber test can be added; 2) the benefit of the deeper radius of investigation of a test flowing at surface is retained; 3) field interpretation is simpler whether surface measurement is possible or not.
Fracture Characterization and Their Impact on the Field Development
Authors: Jadoon M. Saeed K. , Jadoon Ishtiaq A. K. , Bhatti Abid Husaain , Ali Asghar 
Published: December 2007

Abstract
Fracture characterization is a biggest challenge for the geoscientists in sandstone and carbonate reservoirs. With the advancement of all technical capabilities in the acquisition of surface and subsurface Geological data, still it is extremely difficult to understand, characterize, and predict the distribution of fractures in a field. Image logs can successfully be used to locate and to provide directional trends of fractures near the wellbore. However, capturing all the fractures in one well and to predict their flow behavior can still be a challenge. In this paper, a case study of a fractured carbonate reservoir will be presented. The field is currently producing about 500 bbl of oil per day through fractures. Four wells have been drilled on the structure to drain the oil reserves. Water flooding is being carried-out in the field for the last 9 years for pressure maintenance and now 80 % water is being produced. The reservoir has very low primary porosity and permeability, and the flow is through fractures only. On the basis of the three wells fracture data, a new well was drilled, located ideally at a structurally higher position, in crestal area of the field. Image data showed abundance of fractures with different orientation was seen in the well bore but the well didn't flow and that led to its suspension. In this study, fracture data from image logs is compared with outcrop analogs and seismic reflection and interpretation data. In this paper, limitation of the available information, importance of understanding the stress regime, integration of G & G data and lesson learned from the current evaluation of the fracture system and their impact on development of field in Potwar basin will be presented.
A Novel Method to Calculate the Reservoir Pressure of Tight Sand Using the Hydraulic Fracturing Information in the Denver-Julesburg Basin
Authors: Yang Yuanhai , O'Connell Wally , Birmingham Thomas , Hu Guonong 
Published: December 2007

Abstract
Based on the relationship between formation pressure and minimum horizontal stress, as well as the low leak-off rate and abnormal high reservoir pressure commonly observed in tight sand, the authors devised a new method to calculate the reservoir pressure in tight sand using the pre-frac test. Numerous methods have been published to calculate reservoir pressure using pre-frac test. However, all of them require extended pre-frac testing time, taking hours in conventional formation while days in tight sand. It is not practically viable to keep the frac crew waiting so long before a frac can be executed. In contrast, this new method uses the information collected from a 5-minute pre-frac test, which is standard routine for fracs in the Denver-Julesburg basin (DJ basin). Furthermore, this new method has been validated by the conventional well tests conducted by several service companies.
Numerical Simulation and Experimental Studies of Oil Recovery via First-Contact Miscible Water Alternating Gas Injection within Shaley Porous Media
Authors: Al-Mamari F. A. , Al-Shuraiqi H. S. , Al-Wahaibi Y. M. 
Published: December 2007

Abstract
Most clastic reservoirs contain discontinuous shales that act as barriers or baffles to fluid flow and can not be correlated between wells. To our knowledge, there are no published studies on the effect of discontinuous shales on First Contact Miscible Water Alternating Gas (FCMWAG) processes and how they might alter the sweep efficiency. This work aims to remedy this deficiency.
A series of well-characterized laboratory experiments in two-dimensional homogeneous and heterogeneous beadpacks were carried out. Both simultaneous and slug FCMWAG displacement experiments were performed in the porous media containing discontinuous shale. Simultaneous injection was conducted at WAG ratios of 1:1, 4:1 and 1:4. Slug flooding were carried out at a WAG ratio of 1:1 with slug sizes of 5% PV and 50% PV. All experiments were then modelled using IMPES finite difference simulator without using history matching (all simulations used directly measured porous media properties as inputs) to quantify the accuracy of the simulation when modelling the FCMWAG displacements in a porous media with a discontinuous shale.
For simultaneous injection, experiments and simulations have demonstrated that there is an optimal WAG ratio, at which oil recovery is maximized. Additionally, the simulator predicted fairly the location of the bypassed oil which was mainly downstream of the shale unit. However, a poor match was found between measured and predicted water and solvent cuts because in the simulation it is assumed that the injected water and gas flow simultaneously whereas the experiments show that:
solvent and water prefer to flow in segregated paths rather than flowing simultaneously across the whole porous media, and due to the segregate flow, water laterally blocks solvent from contacting the bypassed oil which reduces FCMWAG efficiency.
In slug injection, the large water slug (50% PV) displacement outperformed the 5% PV slug process because the large water slug injected ahead of solvent significantly reduced the extent of fingering and the bypassed oil around the shale barrier. Simulation of the slug WAG experiments showed good agreement for the oil recovery. However, a discrepancy in the physics of the fluid flow during the displacements especially downstream and upstream of the shale barrier was observed in the fluid cut curves. Simulation predicted less fingering and fewer breakdowns of the injected slugs.
Offshore Gas Field Development Optimization Study Applied QA/QC Procedure for Models Accuracy and Decision Reliability "Full Field Compositional Simulation Study—Case History"
Authors: Salameh Lutfi A. , Al Jenaibi Faisal 
Published: December 2007

Abstract
This paper is discussing the main challenges that are still encountered after constructing simulation models incase of not introduced to a practical QA/QC procedure to ensure accurate results for reservoir management decisions.
The study includes the main criteria's which were used to define the optimum development plan for gas production improvement towards achieving maximum recovery.
The field was partially developed in 1989 with 10 gas producers to supply 500 MMscf/day of gas for auto injection into oil rim reservoir. The field is under further development scheme to produce 1.0 Bscf/day to meet the increasing demand of gas for auto injection into other oil reservoirs and for export.
The main difficulties encountered to develop this field are linked to obtain representative model, in addition to other related development aspects of drilling costly gas wells and utilization of the produced gas for auto-gas injection or export.
Several methods (Deterministic and Stochastic) have been introduced to distribute hydrocarbon in the geological model, which was compared later with simulation model estimated initial gas and condensate in-places to ensure achieving more reliable volumes. The current and the future development plans' performances were assessed using detailed compositional simulation model that was constructed based recent rock and fluid characterization studies.
The newly established QA/QC procedure for model's results accuracy has been successfully applied, and the lessons learnt were shared with other simulation teams.
The study main outlines are as follows:
Achieve reliable history match with field data that showed discrepancies. Apply new QA/QC for accurate modeling results and assurance to resolve the common outstanding issues. Develop representative hydraulic lift curves. Develop representative equation-of-state (EOS) for fluid characterization. Optimize the current and alternative development plans.
The results and conclusions of the study are as follows:
– Anomalies screened and defined accurate estimation method for the initial gas and condensate asset volumes. – Correction factor applied to phi-log derived data in order to honor the core derived data. – Developed representative equation-of-state (EOS) and the hydraulic lift curves (HLC). – Constructed reliable full field compositional simulation model matching the field measured data. – New QA/QC procedure has been established to resolve the common outstanding issues. – Evaluation of the current and other alternative development options. – Evaluated the key parameters required to define the required timing of compression facilities.
A Streamline Based Reservoir Management Workflow to Maximize Oil Recovery
Authors: Giordano Ronald M. , Jayanti Shekhar , Chopra Anil , Yuan Hua , Asakawa Kazuhiro , Suleimani Ali , Gheithy Ali , Edwards Clement 
Published: December 2007

Abstract
This paper presents a novel approach to integrated reservoir management in a mature carbonate field. The Lekhwair field (Oman) has been on production since 1976. It has a complex development history, with periods of primary recovery, shut-in, 5-spot, inverted 9-spot, and line drive waterflooding. The challenge is to develop two reservoirs, separated by a shale barrier, using a combination of commingled vertical and horizontal wells.
This paper presents a robust and proven reservoir management workflow that can be used to evaluate short to medium term development scenarios proposed by production technologists. Traditionally, reservoir engineers make medium to long term field development decisions based on complex reservoir models, while production technologists make short term well level decisions based on operational data. As a result, the reservoir engineers and production technologists frequently work independent of each other. This paper provides the workflow and techniques that enable reservoir engineers and production technologists to work in an integrated manner and thereby increase production and recovery in a mature field.
An integrated reservoir management workflow was developed that can help not only the reservoir engineer to understand the reservoir dynamics, but also the production technologist to evaluate everyday production opportunities. This evaluation is brought about by integrating streamlines from finite-difference simulations, well performance data, and novel performance diagnostic plots. This approach was successful in developing a dynamic model for the Lekhwair field. The proposed workflow and applications provide efficient ways to maximize oil recovery in a seamless workflow between reservoir engineers and production technologists.
This paper presents a combination of conventional and innovative techniques that provide a novel workflow for reservoir engineers and production technologists to quickly evaluate various reservoir development scenarios.
Optimal Well Placement for Production Optimization
Authors: Wang Chunhong , Li Gaoming , Reynolds A. C. 
Published: December 2007

Abstract
In the process of reservoir development, we always wish to drill wells at optimal locations so that more hydrocarbons can be extracted at a lower cost. Because well locations in a reservoir simulator are commonly treated as discrete variables, standard implementations of gradient based optimization is difficult so the optimization for this problem is normally done with a non-gradient based method such as the genetic algorithm. Here, we present a novel idea to convert the problem of optimizing on discrete variables into an optimization problem on continuous variables for the optimal well placement. The idea is to initialize the problem by putting a well in every grid-block and then optimize NPV. As the cost of "drilling a well" detracts from the NPV, when NPV is optimized some wells will be shutin (eliminated). For two very simple cases where the problem is to determine the optimal location of a water injection well, we show this problem formulation yields good results with a single injection well remaining after the optimization process.
A Review of Design Considerations for Fracture Stimulation of Highly Deviated Wellbores
Authors: McDaniel B. W. 
Published: December 2007

Abstract
It is reasonably well understood that hydraulic fracturing applications can be especially problematic when a fracture will be initiated from a wellbore that is passing through a reservoir at a trajectory that is highly deviated from the in-situ stress field. Numerous papers and texts are available that have addressed laboratory experimentation or example situations. It is generally recommended to avoid this wellbore condition when possible if fracture stimulation will be required. However, this may not always be possible.
Included herein is a summary review of basic problems that may be encountered when it becomes necessary to apply hydraulic fracturing to a zone with a highly deviated wellbore. Guidelines are offered for how to best adapt the well completion parameters to various specific reservoir conditions, including the following:
In regard to rock hardness and competency, the approach and result in soft rock will normally vary greatly from that of harder rock in more ways than simply permeability. Measured depth and true vertical depth of the zone to be completed should be considered variables. Formation thickness can be an important factor. Single pay vs. multiple zone completions. Thinly stratified pay intervals can be quite different Perforating strategy can be the most important variable; it can often prevent effective stimulation, or conversely, can be used to enable fracturing success.
In some fields, the expanding application of horizontal completions may reduce the use of deviated wellbores. However, environmental concerns for reducing surface footprints during land drilling could increase the use of deviated wellbores. This paper will review the factors most critical to successful placement of hydraulic fracturing treatments in deviated wellbores.
Risk Assessment Based on Single Porosity, Alpha Factor, Dual Porosity Simulation of a Naturally Fractured Rich Gas Condensate Reservoir
Authors: Iwere F. O. , Gao H. , Gomez E. , Ma Y. Z. , Gurpinar O. M. 
Published: December 2007

Abstract
Modeling naturally fractured reservoirs is difficult because of the need to characterize the fractures, matrix and the matrix-fracture interaction. It becomes more challenging if the naturally fractured reservoir produces wet gas, condensates and water. Three different three dimensional, compositional models--single-porosity (SP), single-porosity with alpha factor (SPWAF), and dual-porosity single permeability (DPSP) of the study area, were studied.
The models were calibrated against measured pressure, historical oil production, layer contributions and gas-oil ratios. The calibrated models were then used to forecast the performance of wells in the study area. The impacts of the methodology of describing the natural fractures on fluid flow behavior and recovery mechanisms, as well as on the ultimate hydrocarbon recovery were evaluated. The results also were used to ascertain the risks of selecting the optimum methodology for the field development plan.
The forecasted results show little variations in oil recovery, pressure and oil saturation distributions under identical operating strategy for the three models. This is attributed to the absence of some critical properties required to model the oil recovery mechanisms in dual porosity system. For example, imbibition capillary and relative permeability functions were not input in the dual porosity (DPSP) model. However, the DPSP model is considered more efficient than the single porosity (SP and SPWAF) models because it took less time and modifications to obtain reasonable history match of the field performance. It was also more difficult to obtain a reasonable and acceptable history match using the SP and SPWAF models compared to the DPSP model, and the reservoir properties in the single porosity models had to be modified extensively and unrealistically to obtain history match.