bluuebunny/crossref_metadata_2025 huggingface dataset:
Characterization of Kerogen Reservoirs by Organic Richness from Well Logs: A New Approach for Gas and Condensate Reservoirs in Najmah Formation, North Kuwait
Authors: Acharya Mihira N. , Al-Awadi Mishari A. , Al-Ajmi Saad A. , Al-Eidan Ahmad J.
Published: October 2009

The characterization of the unconventional reservoirs is a challenge. Though the Jurassic formation, Najmah-Sargelu, in North Kuwait fields have been tested and found to be a prolific source-rock as well as a producer of gas, condensate and volatile oil in several wells, but raised the flagged issue as regards to its characterization and predictability for success. The drill stem test (DST) results at some wells are quite successful without any stimulation, while at other wells the DSTs are unsuccessful in spite of advanced and repeated stimulations. Thus resulting a success rate at 50% and categorizing the Najmah-Sargelu as a geologically-complex, naturally-fractured, tight gas and condensate reservoir.

The Najmah kerogen member, formally known as Najmah shale, the source-reservoir composed of highly organic rich argillaceous and calcareous clay, represented by very high total gamma ray values associated with high uranium on spectral gamma logs. The Sargelu limestone, underlying the Najmah kerogen and overlying Dhruma shale, is generally tight and occasionally fractured. Conventional characterization by multi disciplinary data integration and model could not explain the test results, suggesting the key factor making these kerogen reservoirs to producer lies outside our scanned parameters such as structural position, fractures and formation damage etcetera. Conventional petrophysical interpretation and integrated formation evaluation method fell short to explain the unique behavior of such reservoirs.

This paper illustrates the new parameter, organic richness of Najmah kerogen sub-units and the pattern relationship between the success as flowed and unsuccessful as no-flow DSTs from the well data. Thus characterizing the Najmah reservoir based on their organic richness, derived from wireline density logs. This approach has successfully predicted our recent Najmah completed wells. Understanding this critical factor will navigate the 3D model building workflow steps for seismic reservoir description and future development strategy of Najmah in north Kuwait and other regions as well.
Case Study: Integrated 3D Geomodeling of Minagish Oolite Formation, Umm Gudair Field, Kuwait
Authors: Banerjee T. K. , Haider A/Aziz , Kumar Bishnu
Published: October 2009

The Umm Gudair is a large matured carbonate reservoir of Kuwait with a production history of more than 45 years. Umm Gudair has been producing primarily from the Lower Cretaceous Minagish Oolite formation composed of porous limestone consisting primarily skeletal grainstones. In recent past, the main focus of the asset team on this reservoir has been to extend the plateau rate and devise a long term Field development Plan by developing a comprehensive 3D geocellular model which shall be used for running simulation.

Three cases of 3D structural modeling scenarios were considered in order to reduce uncertainty attributed to velocity models. Petrophysical data of 223 wells, Core data from 34 wells, 3D Seismic Cube along with Inversion derived porosity and High Pressure Mercury Injection (Capillary Pressure) data from 102 core-plugs were used to generate 3D property model with the help of advanced 3D geomodeling software. A Facies classification model was built utilizing observations from core description, Log data and training a supervised neural network. Porosity was modeled using sequential Gaussian simulation (SGS) honoring core observations and Seismic derived porosity cube. Modeling Permeability was most critical and complex. Analysis of core data suggested a wide variation in Permeability (between 0.2 to 4000mD) with corresponding porosity variation of 0.08 to 0.30. Average capillary pressure data from core observations was converted to Height Vs Initial Water Saturation (J-Function) and water saturation was modeled.

Despite the abundance of Log, Core, Seismic and laboratory data, creating a truly representative 3D Geomodel was a big challenge owing to complex relationship and distribution amongst various petrophysical properties. This paper highlights the integration of various data and comprehensive steps of building a consistent representative 3D geocellular model used for flow simulation studies and field development planning.
Evaluation of Infill Drilling in the Third Sand Upper Reservoir, Greater Burgan Field, Kuwait
Authors: Ma Eddie , Sanwoolu Ayodele , Abdy Yaser , Al-Jadi Menayer
Published: October 2009

The Third Sand Upper (3SU) is one of the three sub-reservoirs in the Third Sand of the Greater Burgan field, the world's largest sandstone oil field. Initial oil production begun in 1948 and 3SU field development has not been aggressive due to its poor reservoir quality and productivity. After 60 years of primary production, only 7.5% recovery has been achieved.

Infill drilling was identified as a key development strategy in 3SU. In 2008, a simulation study was initiated to investigate infill drilling potential and its impact on production and recovery. We opted for a sector model mainly due to practicality and time constraint. The 780,800 cells sector geological model was scaled-up to 421,632 cells for flow simulation. Due to the sand-to-sand contact with the lower Burgan sands, it is imperative to include these reservoirs in the model to achieve proper energy balance. Accordingly, four pseudo layers were added to the simulation model to allow fluid migration from the lower reservoirs. The 3SU sector simulation model has 100m X 100m areal cells and individual layers with 4-6 feet thickness. Overall, the sector model has 30 times refinement compared to previous 3SU models (Ambastha et al, 2006).

The history match has been carried out for 37 3SU historical wells with 60 years of production history. Detailed study of interactions among field permeability distribution, aquifer strength, fluid migration and fault transmissibility specifications on simulation results was key in developing meaningful history match. Water cut match was less than satisfactory for wells located in the dome area due to modeling deficiency introduced by the pseudo layers. Three infill drilling spacing scenarios were set up to evaluate prediction performance of 800-meter, 400-meter and 200-meter well spacing. Results of the 50-year prediction runs indicated that an incremental recovery of 11% can be achieved by reducing the current well spacing of 800-meter to 400-meter.
Waterflooding Optimization Using Gradient Based Methods
Authors: Asadollahi Masoud , Naevdal Geir
Published: October 2009

Finding the best strategy for production optimization is currently an important research task for closed-loop reservoir management. The closed-loop reservoir management consists of two main tasks: history matching and production optimization. A comparative closed loop reservoir management exercise was performed in connection with the SPE Applied Technology Workshop "Closed-loop reservoir management" in Bruges June 2008. The model used in this exercise was a synthetic reservoir with typical geological features of Northern Sea fields and considerably larger than those used in most previous studies. In a previous work (Lorentzen et al., 2009), a set of history matched models were obtained using the ensemble Kalman filter. We will use these models to investigate the effect of formulation and initial guess on gradient based optimization methods.

Within production optimization, most of the works are focused on optimizing the reservoir performance under waterflooding. We will review the waterflooding optimization studies so far. The mathematical theories of an optimization problem as well as the practical issues regarding reactive and proactive approaches are discussed. The formulation of a waterflooding optimization problem is investigated using three different optimization variables: bottomhole pressure, oil and liquid production rates. Results show that proper formulation improves the performance of gradient based methods considerably. Then it is verified that manual optimization of the initial guess based on reservoir concepts enhances both the result and efficiency of the gradient based optimization. The manual optimization saves the gradient based methods from a number of local optima and also decreases the simulation costs substantially. Two line search methods, steepest descent and conjugate gradient, are used and compared in the adjoint based optimization approach. The conjugate gradient acts slightly faster than the steepest descent method. However, the selection of a proper initial guess is far more important for the performance. Finally, the optimal solution is applied on ten more history matched realizations to check the robustness of the solution. It is shown that the well liquid rates are the best variables used for maximizing the net present value using gradient based optimization. In previous works, well bottomhole pressure has been suggested.
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

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

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

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

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

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

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 (>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

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

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

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

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

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

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.
Challenges in Operating and Developing Strong Bottom Water Drive Reservoir. A Case Hosiery
Authors: Ibrahim Abdullatif , Al Massabi Abdurrahman , Bellah Samir , Al Hashemi Mohamed
Published: October 2009

An offshore Abu Dhabi carbonate oil field was discovered in 1969 and put on production in 1985. The field has two separate culminations producing from a reefal limestone formation deposited in the middle cretaceous. The northern culmination is characterized by good reservoir properties and supported with an active bottom water drive while the southern culmination is characterized by low reservoir properties and hence less support from the aquifer.

Initially the reservoir was developed by vertical and/or deviated oil producers and peripheral water injectors. Soon after production starts, wells water cut gradually increased to reach 50% within 4-5 years with drastic decline in oil production.

Horizontal drilling was implemented with an objective of increasing well exposure to reservoir, reducing drawdown and as such combating water coning/channeling phenomena. Although oil production from horizontal wells was substantially improved, water production trend and production decline, however, did not change in most of the cases.

Application of ESP in southern and northern culminations was initiated to overcome high water cut problem and hence elongates and improves wells production lifting capacity. ESP wells performance shows encouraging results, particularly in the southern culmination.

Managing this offshore reservoir at such high water production is one of the major challenges facing field development engineers. Reservoir heterogeneities, such as fractures and facies distribution, are believed to be main contributors to a water coning/channeling phenomena and to the escalation of water production trends. Therefore, understanding of geological, petrophysical, properties of the formation is the corner stone for , controlling water production problems and hence improving reservoir performance.

This paper provides an overview of the factors that are contributing to the rapid increase in water production and the associated decline in oil production, the vertical wells, horizontal & ESP performance. The paper also assesses new potential ideas for future development aiming towards increasing the sustainable production and recovery.
Shuaiba Transition Zone Reservoirs: From Modeling Studies To Field Development Challenges
Authors: Shiekah Issa Abu , Warrlich Georg , Goossens Peter , Alexander David M. , Zhu Fuping , Lamki Ali
Published: October 2009

Production data from several Shuaiba fields in the Sultanate of Oman demonstrate the oil recovery from capillary transition zones. This is underpinned by extensive detailed experimental and theoretical modeling studies describing favored oil mobility and residual oil saturation in transition zones in the Shuaiba formation reservoir. Nonetheless the economical development of capillary transition zone reservoirs, especially those with thin oil columns, remains an ongoing challenge and necessitates addressing uncertainties related to characterizing the lateral variations in initial oil saturation distribution, water flooding displacement, sweep efficiencies and accurate prediction of oil production.

This paper discusses good practices for ongoing developments of transition zone fields and predicting their performance. The key enablers are: (1) properly characterized initial saturation height functions for long horizontal well planning, (2) implementation of consistent set of hysteresis saturation functions in the reservoir simulation models and (3) geosteering tools for accurate well placement and spacing. Examples of predicted well performances for a field compared to the actual production data will be shown. The results highlight the generic trends in transition zone oil production and the recommended procedures for static and dynamic modeling during field development planning.
Prediction of Heavy Oil Viscosity in Current Reservoir Simulators
Authors: de la Porte J. J. , Riesco N. , Vesovic V.
Published: October 2009

An accurate estimate of oil mobility is essential for reliable exploitation of oil and gas reservoirs, and for development of new technologies, particularly with the industry's increasing reliance on unconventional resources such as heavy oil. The viscosity of heavy oil decreases rapidly with increasing temperature and with increasing concentrations of light components, and can vary over 2-3 orders of magnitude during typical exploration and productions operations. The accurate prediction of the viscosity is therefore difficult, and simple extrapolation of the current methods used in the petroleum industry for predicting the fluid viscosity in conventional reservoirs is fraught with difficulties.

This paper presents a comprehensive analysis of the use of a simple mole-average power law that is based on the Arrhenius equation and used as the default method in some widely used thermal reservoir simulators to predict mixture viscosity. Predictions based on the equation are compared to a set of accurate benchmark data that are based on the best available experimental data for hydrocarbon mixtures. These data cover a temperature range of -175°C to 200°C, and extend to high pressures. The accuracy of the data is better than 5%, sufficient for validation purposes. We summarize the conditions under which the simple power law provides reasonable estimates of viscosity, identify the ranges of pressure and temperature and composition for which large deviations can be expected, and discuss the implications of using the equation to predict heavy-oil viscosity. We demonstrate that the current practice of fitting scarce experimental data and using the viscosity of the heavy fraction as an adjustable parameter is problematic, and that extrapolation in temperature or to similar mixtures is highly unreliable.
Case Study: History Matching Using Enhanced Permeability Modifications (EPMs) for Court Bakken Heavy Oil Reservoir
Authors: Taabbodi L. , Osiowy G. , Hagstrom C. , Galdon L.
Published: October 2009

Computer modeling of heavy oil reservoirs has become progressively more challenging in order to represent geological reality and its impact on fluid flow. A method has been developed in which completion, production, and injection information, coupled with the static well data, are used to model enhanced permeability channels that have been created around the wells as a result of production and/or injection.

Court heavy oil field located in West Central Saskatchewan, Canada is a Bakken heavy oil reservoir (17°API, in-situ viscosity of ~155 c.p). The field, which has been under an active waterflood depletion strategy for the last 20 years, has achieved a recovery factor to date of ~ 24%. The geological complexities found in the Bakken Formation at Court introduce many challenges for history matching. It was discovered that successful history matching required the introduction of enhanced permeability modifications (EPMs). The EPM regions were superimposed over the geological model. Flow simulations using the EPMs region concept resulted in a significant improvement in the overall quality of the history match at both the group and field levels. Sensitivity studies were also undertaken to determine the minimum EPM requirement to gain the history match.

This paper describes how to use completion, production and injection data in the flow model to predict the high permeability zones in the vicinity of a wellbore. As it will be discussed in more detail, this technique allows for the achievement of a reasonable history match using a Black Oil reservoir simulator. The model was history matched to liquid rate, water cut, and pressure. The simulation model has been used to evaluate the current waterflood and predict the possible future enhanced oil recovery (EOR) opportunities for this field.
A Simple Method for Accurate Prediction of Temperature Drops in Natural Gas Production Systems for Black-Oil Models
Authors: Bahadori A. , Vuthaluru H. B.
Published: October 2009

Accurate prediction of the temperature drop accompanying a given pressure drop for the natural gas production well is necessary in the effective design of natural gas production facilities. Current rigorous compositional models depend on many variables and require information about fluid composition. In this paper, a simple-to-use method which is easier than current available models, is presented to predict accurately the appropriate temperature drop accompanying a given pressure drop in natural gas production wells based on the black-oil model to get a quick approximate solution for the temperature drop of a natural gas streams in gas production wells. The obtained results illustrate that excellent agreement is observed between the reported data and the values calculated using the new developed method. Considering the results, the new developed correlation is recommended for rapid estimation of wellbore temperature drops in gas production wells for pressures up to 45 MPa and pressure drops up to 25 MPa. This Simple-to-use approach can be of immense practical value for the gas reservoir and production engineers to readily estimate temperature drops in gas production wells at various conditions. In particular, personnel dealing with natural gas production activities would find the proposed approach to be of immense help and user friendly involving no complex expressions with transparent calculations.
Modeling Well Performance in Shale-Gas Reservoirs
Authors: Cipolla C. L. , Lolon E. P. , Erdle J. C. , Tathed V.
Published: October 2009

The paper focuses on modeling well performance in shale-gas reservoirs using numerical simulation. Stimulation treatments in many shale-gas reservoirs create very complex fracture networks. These fracture networks are required to achieve economic production rates from rock with a matrix permeability of 1e-4 to 1e-5 md. The primary issues with modeling production from shale-gas reservoirs are accurately describing gas flow from the tight shale matrix into the fracture network, properly characterizing the matrix block size (or fracture density) and the conductivity of the network fractures, and evaluating the impacts of stress sensitive network fracture conductivity and gas desorption. This paper contrasts numerical reservoir simulation approaches using discrete modeling of the tight matrix and fracture network to that of dual porosity models. The paper illustrates that discretely gridding the network fractures is required to accurately model fluid flow in shale-gas reservoirs (with complex fracture networks) and show that dual porosity solutions do not adequately capture the transient flow in the very low permeability matrix blocks. The paper also illustrates the impact of gas desorption on the production profile and ultimate gas recovery in various shale reservoirs, showing that in some shale-gas reservoirs desorption may be a minor component of gas recovery. In addition, the paper details the impact of stress sensitive network fracture conductivity on well productivity. The reservoir simulations show that as closure stress increases in the fracture network, significant reductions in network fracture conductivity are likely, decreasing ultimate gas recovery. However, the effects of stress sensitive network fracture conductivity may not be evident in the initial well performance (1-2 years) and could lead to optimistic gas recovery forecasts. The paper presents selected examples from Barnett shale horizontal wells that incorporate microseismic fracture mapping and production data to illustrate the application of the production modeling to evaluate well performance in unconventional gas reservoirs.
Horizontal Well Design Incorporated with Interwell Interference, Drilling Location, and Trajectory for the Recovery Optimization
Authors: Lee J. W. , Park C. , Kang J. M. , Jeong C. K.
Published: October 2009

The paper presents a horizontal well-design economically optimized by GA(Genetic Algorithm), which considers drilling location, various trajectories, and drilling cost. Previous designs for the production well have been limited at selecting the drilling spot and placing the fixed-shape trajectories to maximize the cumulative production. They are difficult to produce the systematic design that covers whole reservoir characteristics since they concentrated on only the location or the fixed trajectory for additional one well or two wells. Furthermore, they are incapable of fully investigating the interference effect among the producing wells in a heterogeneous reservoir as well as the profit maximization at the view point of economist.

The optimization model integrates GA with a node-based configuration that allows several kick-off points for the horizontal well-designs. The chromosome of GA involves the data regarding the location coordinates, the number of kick-off points, the trajectories, and the number of wells. The object function evaluates the profit consisted of production rate and cost information related to drilling and operation. Waterflooding with one injection well is carried out and the effect of inter-well interference is examined in a heterogeneous reservoir.

The developed model improves both profit and cumulative production comparing with the conventional vertical well-designs. The wells are distributed sparsely due to the interwell interference meanwhile they are assembled in higher permeable zones of a heterogeneous reservoir. The approach makes it possible the more reliable well-design considering several kick-off points, well placement, and various trajectories.
On State Constraints of Adjoint Optimization in Oil Reservoir Water-flooding
Authors: Suwartadi E. , Krogstad S. , Foss B.
Published: October 2009

Optimization on large scale reservoir models may be prohibitive in terms of run-time. The adjoint based method is an efficient way to compute gradients in such systems. The presence of state constraints however may be detrimental to computational efficiency. In this paper we explore the use of adjoints and the interior point method for reservoir problems, in particular the optimal production setting problem with state constraints. State constraints typically include limits on water saturation in grid blocks close to producer wells or limits on water production rate. Results are encouraging since computational efficiency is maintained in the two examples which are studied in this paper.