bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sequence Stratigraphy in a Carbonate Prograding Margin; Implications for Dynamic Flow Modeling and Field Development
Authors: Grausem M. , Lawrence D. , Al Shemsi M. 
Published: October 2009

Abstract
This paper concerns a super-giant carbonate oil field in Abu Dhabi, UAE (first oil production in1962). Remaining reserves are mostly located in Lower Cretaceous carbonate build-up and prograding basin-margin deposits of the Shuaiba Formation. The principal challenges to maintain future production are pressure decline and uneven water advance.
A key to understanding dynamic flow behavior is the spatial distribution of flow barriers, facies, diagenesis and faulting / fracturing in the prograding clinoform domain. The static model needs to accurately capture these heterogeneities by combining interpolation of reservoir parameters from wells with structural and sedimentological trends extracted from 3D seismic data.
A comprehensive work program was initiated to understand the depositional evolution of the reservoirs using a sequence stratigraphic approach. The application of high-resolution sequence stratigraphy (recognition of 3rd and 4th order sequences) associated with detailed seismic interpretation of the clinoform domain represents a new approach rarely successful in carbonate reservoirs. Low permeability carbonate mudstone facies associated with transgression in the clinoform domain create local vertical barriers to fluid flow. The progradational clinoform topsets contain the best reservoir facies with a thickness distribution systematically related to position within the clinoform.
Sequences of 3rd and 4th order have been interpreted to generate a seismically constrained stratigraphic framework. High quality 3D seismic combined with a thorough description of stratigraphic architecture provides a new approach to populating the reservoir model with reservoir facies (former lithostratigraphic units) honoring the depositional shapes from seismic interpretation. Combining the stratigraphic surfaces of the clinoforms with the lithological surfaces as property boundaries derived from the progradational geometries represents a new approach to reservoir modeling.
The current pressure maintenance scheme is through peripheral water injection, with some pattern injection in the lower parts of the clinoforms. The preferred flow paths of injected fluids are strongly controlled by the geometry of clinoforms, and an understanding of this enables more accurate prediction of the pressure fronts and future water / gas breakthrough. Development optimization plans currently being evaluated will incorporate the reservoir property trends derived from the spatial distribution of stratigraphic sequences (3rd and 4th order). The location of proposed simulation and production pilot patterns has been based a facies interpolation methodology within a sequence stratigraphic framework.
Permeability Prediction and Characteristics of Pore Structure and Geometry as Inferred from Core Data
Authors: Permadi P. , Susilo A. 
Published: October 2009

Abstract
A quick, inexpensive way to maximize the use of routine core analysis data is desired to support both geological and engineering works. Better understanding about pore structure and geometry that relate to hydraulic characteristics of a pores system can lead to improved reservoir characterization.
The objectives of this paper are to present techniques to improve permeability prediction and identify the implications of relationship between pore structural and geometrical attributes on hydraulic characteristic of rock samples. The present work is based on equations of capillary model. The equations in fact contain three important hydraulic parameters: mean and effective hydraulic diameters as the geometrical parameters and hydraulic conductivity as the structural parameter. These parameters and porosity are the main variables to be used in the crossplot analysis and interpretation.
This work is facilitated with two core data sets of sandstones and carbonates. It is demonstrated that crossplot of the effective hydraulic diameter against porosity can be used to predict permeability. Comparisons between this technique and the previous one show that the present technique results in less scatter data points and overall gives better permeability prediction. The crossplot of either effective or mean hydraulic diameter versus hydraulic conductivity works perfectly in dividing all the data points into several distinct groups. The data points of each group are lining to form a straight line. Two and four distinct straight lines with different slopes are formed, respectively, for the sandstones and carbonates. These are in excellent agreement with the electrofacies and the result of Leverett's J-Function analysis. Overall, this paper provides the related theoretical background and detailed discussion on the results, giving better understanding about pore structure and geometry and its relation with permeability and rock typing.
Effective Reservoir Management Through Integration of Formation Pressure While Drilling, Well Log and Seismic Data in the White Rose Field, Offshore Newfoundland, Canada
Authors: Hammou Nasr-Eddine , Harris Tony , Carter James E. , MacFarlane Curtis , Mishra Vinay K. 
Published: October 2009

Abstract
Understanding reservoir compartmentalization is one of the key aspects of effective reservoir management. The optimization of production and injection wells is a key objective of this process. Integration of seismic, formation tester and other data along with production results, provides valuable information about reservoir compartmentalization.
This data integration concept was applied to characterize reservoir connectivity in the central development region of the White Rose Field. The reservoir interval consists of a thick Cretaceous-aged sandstone reservoir (Ben Nevis formation) located offshore Newfoundland, Canada. The field development strategy involves drilling horizontal producers and a combination of deviated and horizontal injectors. Production/injection began before drilling of all wells in the field, leading to drilling under dynamic conditions in a field that achieved oil production rates in excess of 135,000 bbl/d.
Prior to production, the White Rose Field appeared relatively homogeneous with well-connected flow units, although reservoir heterogeneity and fault compartmentalization were considered the greatest risks to recovery. Subsequent dynamic multi-disciplinary data obtained during production highlights specific intervals of compartmentalization allowing for a focused approach in dealing with heterogeneous flow. Formation pressure while drilling (FPWD) data, acquired in newly drilled horizontal or deviated wells, indicate complex flow paths between injector and producer. A combination of pressure data from multiple wells, petrophysical interpretations, geophysical analysis, and production data, provides important information about reservoir connectivity and the transmission properties of several faults.
This paper describes how an integrated approach, along with the implementation of new technology measurements, facilitated effective reservoir management. The integration of the data to transform the pre-production reservoir characterization into a synproduction simulation model is elaborated upon. The discussion also addresses the sealing nature of the faults and vertical barriers to flow. The process has been useful in managing the production and injection wells, as well as determining the drilling requirements for infill wells.
Application of a Systematic Technique for the Dynamic Characterization of Carbonate Gas Condensate Reservoirs
Authors: Yong LI , Bao-zhu LI , Yong-le HU , Jing XIA , Ying SHI , Xing-liang DENG 
Published: October 2009

Abstract
This paper presents the concept of dynamic characterization of the carbonate gas condensate reservoirs, which mainly involves production analysis, material balance method and well test interpretation in combination with geological analysis results. This systematic technique can be fully integrated with the long-term low accuracy data of dynamic production and short-term high-precision data of transient well testing, in order to correctly evaluate the properties of the reservoir around the well, such as the formation permeability, well skin, oil drainage radius and dynamic reserve and so on. Then based on the results, the "dynamic characterization model" can be built to predict the performance of the wells. Take the development pilot blocks in Tazhong No.1 carbonate gas condensate field as an example to elaborate the details of this method. The results show that the new material balance equation can accurately calculate the original gas in-place of carbonate reservoirs in both fracture system and matrix system; the combination of analytical and/or numerical production analysis and well test analysis with production data constrained can correctly evaluate the formation permeability, well skin, and dynamic reserve; These three methods are integrated and constrained with each other, which can generate a reliable result; Both the material balance method and the "dynamic characterization model" are applied to the performance prediction of the wells and the block. This systematic technique has been successfully applied to "Tazhong No.1 Carbonate Gas Condensate Field Pilot Pre-Development Plan with 1 Billion Cube", which provides a reliable foundation for the effective development of Tazhong No.1 gas field.
Prediction of Crude Oil Viscosity and Gas/Oil Ratio Curves Using Recent Advances to Neural Networks
Authors: Oloso Munirudeen A. , Khoukhi Amar , Abdulraheem Abdulazeez , Elshafei Moustafa 
Published: October 2009

Abstract
This paper proposes and implements a new approach for predicting Pressure -Volume-Temperature (PVT) properties of crude oils. Instead of the usual single or multi-data point prediction for any crude oil PVT property that is described by a curve, the approach in this study predicts such a property over a specified range of required reservoir pressures. Moreover, the shapes of the predicted curves are smooth and consistent with the experimental curves. Prediction models based on Artificial Neural Networks (ANN) and two of its advances; Support Vector Regression (SVR) and Functional Networks (FN), have been developed to execute the formulated approach.
The approach has been demonstrated for viscosity and solution gas/oil ratio (GOR) curves. These two properties vary with reservoir pressures and they are often required to be estimated over a specified range of pressures. In this study, three different data sets have been used. The first Data set consists of 12 variables which are the predictors, including crude oil hydrocarbon and non-hydrocarbon compositions and some reservoir properties. The other two data sets consist of laboratory viscosity-pressure measurements and laboratory gas/oil ratio-pressure measurements for plotting the viscosity and solution GOR curves respectively. In the simulation results, SVR and FN give better performances than the conventional ANN technique. Graphical plots and two common statistical measures (root mean square error, RMSE, and absolute percent relative error, AAPRE) have been used to evaluate the performances of all the developed models.
Development of Generalized Porosity-Permeability Transforms by Hydraulic Units for Carbonate Oil Reservoirs in Saudi Arabia
Authors: Shenawi Shamsuddin , Al-Mohammadi Hisham , Faqehy Muteb 
Published: October 2009

Abstract
There are several types of porosity-permeability transforms to determine permeability from well log-derived porosity in uncored oil and gas wells. Widely used typical transforms, either by geologic zones or by facies, do not provide satisfactory permeability to be distributed in reservoir simulation models. Hydraulic Unit (HU), which is a technique of rock typing of reservoir, provides far superior transforms than typical transforms. In this work, available routine core data, from major carbonate oil reservoirs located in eight different oil fields of the Kingdom of Saudi Arabia, are assembled to develop improved generalized porosity-permeability transforms by Hydraulic Units (HU).
Improved transforms by HUs were developed for major carbonate oil reservoirs in eight different oil fields. Correlation accuracy (R2) of each transform by HU was very good (&gt;0.9). Then all data from eight different fields were combined to develop generalized transforms by HU technique. This technique provided excellent transforms for various HUs regardless of rock fabrics—either limestone or dolomite.
Developed generalized transforms by HUs were tested for their accuracies on acquired core data in two wells, completed in the same major carbonate reservoir, but in two different oil fields. Applicability of generalized transforms was also tested with the core data from a different secondary carbonate reservoir. Calculated permeability by HUs matched very well with the tested core data which enhanced the reliability of developed generalized transforms.
Similarly, generalized vertical permeability transforms by HUs were developed for the same major carbonate reservoirs in eight fields. Calculated vertical permeability by HUs matched very well with core data as well. Then vertical to horizontal permeability ratios (kV/kH) by HUs were calculated using both generalized transforms for vertical and horizontal permeability. The kV/kH ratios for most of the HUs are found to be almost one under the laboratory condition.
Fluid Discrimination Applying AVA Potentiality for Carbonate Reservoir in U.A.E.
Authors: Mahmoud Sabry L. , Othman Adel A. , Soroka William L. , Al Jeelani Abu Baker 
Published: October 2009

Abstract
Well based modeling and seismic data analysis were used to investigate the potential of Amplitude Variation with Angle (AVA) for fluid discrimination in a high porosity carbonate reservoir in a producing UAE oil field. Gassmann fluid substitution was used to model well log data, which included compressional and shear sonic logs and density logs to produce synthetic well logs representing the reservoir at 100% fluid saturations of brine, oil and gas at reservoir pressure and temperature conditions. The average VP/VS ratio for brine saturated reservoir (~2.0) was observed to be higher than both the oil (~1.7) and gas (~1.6) saturated reservoir cases.
The modeled brine, oil and gas logs were used to calculate the AVA responses at the top and base of a thick, 25-35 % porosity reservoir layer using the Zoeppritz equations. The responses for all three fluids were found to be a Class-IV type AVO anomaly. Seismic amplitude variation on the synthetic CDP gathers was successful at discriminating brine from hydrocarbon but could not differentiate oil from gas. These encouraging results on synthetic data suggest that with good quality seismic data it can be possible to see a difference in AVA responses between brine and hydrocarbon filled porous reservoirs. An AVA study was performed using available relative amplitude CDP gathers along a 2D seismic line extracted from a 3D seismic volume. The results were able to discriminate between areas saturated with brine from those with hydrocarbon. The real seismic results were in good agreement with synthetic model results. The angle stack analysis was successful at improving the signal-to-noise ratio in lower fold seismic data and reduced the input data size requirement when dealing with larger CMP gathers. The effects of varying key reservoir and seismic properties on AVA response were examined to help understand the potential for misinterpretation.
Modelling Formation Damage and Reservoir Chemical Treatment for Improving the Clastic Reservoir Petrophysical Properties and Hydrocarbon Production as Exemplified on Northern and Central Saharan Basins, North Africa
Authors: Makhous Monzer 
Published: October 2009

Abstract
Different laboratory models were elaborated and applied to fields for HC enhanced recovery. Most of these models performed a 1.6 to 4.7-fold increased reservoir filtration proprieties. In some rare cases, the applied treatment has not improved the recovery, while only in two cases the procedure resulted in production degradation. Undesirable effect was due to the partial dissolution of some rock fabric constituents such as opal and chalcedony by HCl and HF. Acid treatment involves also surface activation, which results in increased amount of the mineral-bound water and, consequently, in decreasing rock permeability. This requires stabilization of swellable clay minerals.
For this purpose, the treatment of reservoir rocks from northern Saharan fields with calcium chloride performed increase of reservoir filtration capacity for two- or even three-fold. The repeated treatment has not produced a substantial increase of the permeability. The favourable effect of CaCl2 treatment is plausibly explained by the change of the film thickness of bound water in the pore space as well as by the replacement of Na+ cations by Ca2+ cations in swellable clay minerals.
This process promotes also the dehydration of sandstone clay cement and desorption of asphaltenes and resins in the stratum. The treatment of the argillaceous cement of sandstone in the reservoir with KCl, HCl and CaCl2 solutions produced decrease in clay swelling by 10 to 50 %. However, the inclusion of solvents, inhibitor agents such as monovalent and polyvalent salts, polymers, emulsion agents and some crude fractions considerably improves protection and stabilization clay minerals in sandstone cement and contribute to minimizing the reservoir plugging. The described approach is at present extended and applied successfully to fields in other basins.
Successful Application of 3-D Seismic Technology on Middle Cretaceous Carbonate Reservoir—Significant OIP Increasing
Authors: Al-Shateri Abdullah , Bellah Samir , Furuya Keiichi , Umezawa Yoshihiko Tamura 
Published: October 2009

Abstract
Current 3-D seismic data with state of the art processing and interpretation technology has revealed a clear picture of the reservoir boundaries, extension and characteristics. Consequently significant Original Oil In Place increment has been recognized in a field offshore Abu Dhabi, U.A.E., which is unusual case in this region. Several approaches were applied to achieve accurate reservoir images. Seismic sequence stratigraphy, AI inversion, waveform classification etc., were utilized to define the reservoir limit. Vertical stretch and map migration methods were applied to investigate the sensitivity to the velocity hence achieve more reliable depth structure map. Co-blending of several 3-D seismic attributes was applied to identify subtle faults and fracture swarms. New structures were identified with a great degree of accuracy through statistical analysis and sensitivity test of depth conversion, with narrow uncertainties ranges to optimize well location and field development plan.
Integrated Reservoir Connectivity Study of Ahmadi Fractured Reservoir in Bahrain Field
Authors: AL-Muftah Ali , Kumar K. , Murty C. R. K. , Lemaux Thierry , Ranjan Amit , Dejoussineau Ghislain , Bertrano Charles , Behira Hermann 
Published: October 2009

Abstract
This paper describes how the fracture model for Ahmadi was incorporated into a single and dual porosity simulation model. It highlights the approach and methodology that has been used for understanding the reservoir connectivity and its drive mechanism. In addition, the effect of dual porosity model in improving the initial history match of the reservoir performance and its recovery mechanism has been studied.
The two Ahmadi carbonate reservoirs in Bahrain Field (Aa and Ab) are thin, highly faulted and irregularly-fractured. The complexity of these reservoirs has prevented an efficient recovery with average production of wells to 15 Bopd. This has prompted a detailed integrated study to fully understand the recovery mechanism and to increase the wells' productivity.
A conceptual model has been developed for the reservoir connectivity of Ahmadi reservoirs by integrating static and dynamic data. This comprehensive study that integrates transient welltesting and production data with cores and image logs to map fracture network derived using seismic facies has resulted in improving the understanding of reservoir connectivity and flow mechanism. This was accomplished by building Discrete Fracture Model (DFN) that was tuned and validated using sector local well test models to match KH and pressure responses.
In order to reduce uncertainties in the model, different scenarios were built for different fracture intensity and aperture to derive appropriate parameters to pass to reservoir simulator for full field simulation. DFN model output was used in both single and dual porosity models to obtain production performance of the reservoirs.
3D Seismic Attributes - A Better Tool For Well Placement In Complex Reef Build-Ups
Authors: Najia Walid , Bellah Samir , Al Shehhi Jamila 
Published: October 2009

Abstract
This middle cretaceous reef build up reservoir has similar problems to other fields of similar setting in the region, regarding upper contact in the form of Karstification with a mixture of fill, shally interbedding, lateral / vertical tight intervals, uneven Vug distribution and large transion zone.
Those have presented a great challenge to adequately place horizontal wells, where near surface well path will intercept the Karsts topography extending in the reservoir with its potential drilling hazard while away from the surface wells will end up in high SW zone. In this context, well placement becomes a real challenge. Few wells had to be plugged and side tracked adding several million dollars to the drilling cost beside the lost in hole equipment.
After our 3D OBC seismic survey, the team attempted and succeeded in using (for the first time) a group of seismic guided Reservoir characteristic attributes to identify a sweet spot (in our case a sweet level) and develop a well path plan that properly placed the well trajectory deep enough away from Karst and surface irregularity avoiding the danger of drilling hazard and penetrating the upper layer, yet shallow enough not to fall within the high water zone.
Our success story is supported by wire line image log and acoustic logs and keeping the well cost at reasonably estimated values.
The paper reviews difficulty normally faced in drilling those wells, summarize original work carried out in selecting seismic guided attributes (as part of the reservoir characterization) to build a well design based on those findings. The paper will finally present a successful drilling case of 2700 ft supported by wireline logs.
A Fully Coupled Three-Phase Model for Capillary Pressure and Relative Permeability for Implicit Compositional Reservoir Simulation
Authors: Hustad Odd Steve , Browning David John 
Published: October 2009

Abstract
A coupled formulation for three-phase capillary pressure and relative permeability for implicit compositional reservoir simulation is presented. The formulation incorporates primary, secondary and tertiary saturation functions. Hysteresis and miscibility are applied simultaneously to both capillary pressure and relative permeability. Two alternative three-phase capillary pressure formulations are presented, the first as described by Hustad (2002) and the second that incorporates six representative two-phase capillary pressures in a saturation weighting scheme. Consistency is ensured for all three two-phase boundary conditions, through the application of two-phase data and normalized saturations.
Simulation examples of water alternating gas (WAG) injection are presented for water-wet and mixed-wet saturation functions. 1D homogeneous and 2D and 3D heterogeneous examples are employed to demonstrate some model features and performance.