bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Application Of Different QI Techniques To Improve The Static Reservoir Model For A Clastic Onshore Oil Field In Oman
Authors: Scholten-Vissinga M. 
Published: September 2013

Abstract
A quantitative interpretation (QI) study has successfully predicted the distribution of sands and shales in the Upper Gharif. This was indisputably confirmed by three wells drilled after completion of the QI study. By integrating a range from low to high "tech" QI technologies, a workflow in a land environment could be developed that enables us to delineate channel sands with challenging rock properties at a fairly deep target. Integral part of this workflow comprehends the alignment of the petrophysical data, seismic data and production data in a consistent manner. Then, joining the maps from RMS amplitudes, spectral decomposition and seismic facies classification with products from the AVO inversion allowed us to construct a confidence map, which assigns areas with different probabilities to encounter these channel sands.
Building further on this QI success, the first 3D Close-the-Loop (3DCtL) project in Petroleum Development Oman (PDO) ever was initiated. This methodology strives to obtain an accurate as possible static reservoir model, which is consistent with all available subsurface data. The workflow consists of two main steps. Firstly, a rock property model is derived from well data and then the reservoir properties (net-to-gross, porosity and hydrocarbon saturation) in the static model are used to generate synthetic 3D seismic data and compared with the measured surface seismic data. In case of disagreement, the second phase involves a stochastic seismic inversion which updates the reservoir properties and makes them consistent with the measured seismic data. While running through this workflow, a number of deficiencies in the static reservoir model came to surface. Besides improvement in the thicknesses of the layers away from well control and in the velocity model used for time-depth conversion, the main enhancements from the stochastic inversion amounts to more realistic net-to-gross and porosity estimates and improved insight in the sand distribution in the Al Khlata reservoir. Ultimately, the subsurface uncertainties are considerably reduced and result into improved reserve estimates.
The significance for PDO is that although this technology is well established in most major oil companies, this is the first time it has been successfully applied on a PDO seismic data volume.
Reservoir Characterization for Improved Petrophysical Properties Predictability & Validations: Capillary Pressures and Permeability (Niger Delta Province as Case Study)
Authors: Haruna Onuh , Ogbe David , Chike Nwosu 
Published: September 2013

Abstract
Permeability and initial saturation are two key reservoir parameters to be defined in subsurface reservoir models. The prediction of these parameters is particularly challenging since they cannot are not abtained directltly from downhole well logs. In this paper, we focus on characterization of pore systems at core plug scale to provide improved models for permeability and saturation prediction. The wider implication of the workflow presented is that they offer better integration between methods used for saturation prediction and methods used for permeability prediction.
We examine the use of Mercury Injection Capillary Pressures (MICP) for genetic unit classification and for predicting permeability and saturation. The method is based on a NORMALIZED PORE THROAT APPROACH (Rtot¯) with Niger Delta as case study. Petrographic observations of pore types are analysed alongside MICP data and air permeability for a number of genetic reservoir units. A correlation coefficient, R2 of 0.81 is obtained for permeability - Rtot¯ plot compared to R2 of 0.56 for the porosity-permeability plot. We also investigated Volotikin's method for generating primary drainage capillary pressure curves from NMR logs, to generate pore throat radius as input to Rtot¯.
Model Validation with reference to existing Flow Zone Indicator (FZI) based approach, NMR based methods by SDR and Coates, and the existing core derived permeability correlation for an Offshore Niger Delta Field.
ICD Completions` Optimization for an Offshore Abu Dhabi Well Using Dynamic Modeling
Authors: Hashemi Mohamed Al , Bellah Samir , Gurses Sule , Akhtar Muhammad Nadeem 
Published: September 2013

Abstract
A study was conducted to determine the optimum re-completion for an offshore Abu Dhabi well. The candidate well was completed as open hole in a complex carbonate reservoir with faults and fractures and suffering from rapid increases in water cut. To quantify the value of re-completing the well with ICDs completions, a dynamic simulation modeling and optimization workflow was applied.
To evaluate the best completion design, the dynamic model was refined and history matched in the sector area of the well using multi-segmented well technique. The number of downhole compartments (sections between packers), location of packers and ICDs flow area were simultaneously optimized to determine the best completion options for the candidate well using an objective function that included both; the value of oil and the cost of water. The ICD flow area per compartment was reverse engineered into an appropriate number of ICD joints and set of nozzles as part of the completion design process.
The workflow provided a quantitative method for choosing the most appropriate horizontal well completion and demonstrated significant value for installing downhole flow control devices. The presentation of the results in terms of oil gain and water reduction for the different objective functions provided a clear indication about the best completion options, depending on the cost or aversion for water production versus the value of oil.
Minimum Miscibility Pressure Measurement with Slim Tube Apparatus - How Unique is the Value?
Authors: Ekundayo Jamiu M. , Ghedan Shawket G. 
Published: September 2013

Abstract
Over the years, the slim tube experiment has been the most commonly used laboratory technique for determination of minimum miscibility pressure (MMP) for designing field miscible floods. However, till now, the design of these experiments is not standardized, neither in terms of set-up nor procedure. Often, the set-up, characteristics of the slim tube coil and even the experimental procedures are left to the discretion of the experimentalist, leading to very uncertain and non-unique MMP values, to say the least. Not just the uniqueness is of great concern, but also the lack of measurement repeatability; two measurements using same fluid samples under the "same experimental conditions" may result in too different MMP values. Matching these experiments with any PVT simulation package may pose a challenge, which even if a match is achieved, may be of questionable reliability. It is on this premise that this work was based.
Slim tube experiments were designed and performed to study the effects of some parameters on the uniqueness and repeatability of the MMP measurements. It was found that MMP measurements are different with different injection rates. The lowest tested rate showed slightly lower MMP and better recovery performance than the other tested rates. No clear trend was noted, however. MMP was found to be lower for the larger coil diameter of the two investigated. MMP decreased as the coil length increased. The decrease in MMP with increase in coil length followed a parabolic trend.
It was, therefore, concluded that laboratory measurements of MMP using the slim tube apparatus is a function of not just the characteristics of the interacting fluids but also those of the coil used as well as the choice of injection rates. The experimental design and procedure need to be unified to produce more reliable MMP data. It is the recommendation of the authors to design the experimental injection rate based on the expected field gas injection, to use the largest coil diameter possible, and to design the coil length, based on the expected well spacing between the injector and producer.
Safeguarding Reserves of a Large Carbonate Waterflood Field by Preventing Induced Fractures
Authors: Al Waheibi Hamed , Garimella Sai , Wardy Widad 
Published: September 2013

Abstract
The case study carbonate field has been developed by waterflooding. Presently, only the produced water is re-injected into 50 wells with voidage replacement ratio being less than unity at field level. Declining pressure trends due to suboptimal voidage replacement balancing and continuous drilling activities require rigorous monitoring to avoid dropping below a critical reservoir pressure (13000 Std. Units ) level at which the hydrostatic head could initiate fractures in the reservoir. Injection under fracturing condition is not an option for field recovery furthermore preventing artificial fractures will be safeguarding 40% of expectation reserves in three specific injection patterns.
A geo-mechanical study was conducted to understand the dependency of fracture pressure on reservoir pressure depletion, including temperature effects. A geo-mechanical model was generated using well logs such as density & sonic that was calibrated with lab tests for rock mechanical properties and leak-off tests together with pore pressure for stress model. This model was then used in the estimation of fracture pressure dependency on reservoir pressure using poro-elastic theory. A pragmatic diagnostic tool was then developed for establishing the field pressure operating envelope, where the injection pressures are plotted against reservoir pressures and compared to the field operating envelope at pattern level.. This tool helps identify which patterns are at potential fracturing risk. i.e. above fracture pressure model. Consequent to identification of risky patterns, mitigation measures are implemented by reducing water injection rates and/or reducing offtake rates to adjust sector pressure within the operating envelope. This remediation is practiced rigorously every quarter for all the patterns with the availability of updated reservoir pressure data. So far no indication of induced fractures from downhole temperature gauges or anomalous water-cut behavior is seen. With the effective injection pressure/rate management, field ultimate recovery is estimated to be 33%, exceeding the top quartile recovery factor (32%) and a sustained expectation oil production forecast for the coming 7+ years. To further enhancing the voidage replacement, two supply water wells were drilled for supplementing water injection
In summary, better management of waterflood projects dictates controlling injection strictly below fracture pressure compared to maintaining injection closely above bubble point pressure. The proposed waterflood field management methodology adopted is generic and the diagnostic tool developed can be utilized routinely for preventing induced fractures in matrix waterflood projects.
Does the Double Layer Expansion Mechanism Contribute to the LSWI Effect on Hydrocarbon Recovery from Carbonate Rocks?
Authors: Al-Shalabi Emad W. , Sepehrnoori Kamy , Delshad Mojdeh 
Published: September 2013

Abstract
Wettability alteration mechanism is still believed to be the main contributor to low salinity water Injection (LSWI) effect on oil recovery from carbonate rocks. This paper makes an attempt to explain the double electric layer expansion as a main mechanism and contributor to LSWI effect on oil recovery from carbonate rocks. The existence of double electric layer expansion mechanism in carbonate rocks is investigated through history matching recently published coreflood experiments using the wettability alteration option in the UTCHEM simulator. The history match results suggest that wettability alteration has negligible effect on water relative permeability. The negligible change in the water relative permeability is also consistent with the double electric layer expansion whereas the immobile water film thickness increases and hence the relative permeability remains constant. This paper provides a basis to develop a LSWI model to predict oil recovery from carbonate rocks.
Risk Analysis for a Fracture Offshore Abu Dhabi Reservoir
Authors: Abou Ali Mouyhna , Games Federico German , Bourdarot Gilles Jean 
Published: September 2013

Abstract
This field case present a risk analysis on production, plateau duration and ultimate recovery factor performed on a fractured carbonate reservoir.
The field has been under early production for more than 48 years, with less than 2% cumulative produced Oil. Historical data measurements on Well Production Oil Rate, Well Gas Oil Ratio (GOR), Well Static Pressure and Well Bottom Hole Flowing Pressure have been utilized in order to constrain uncertain parameters during historical period and then propagate into prediction.
The risk analysis takes into account reservoir uncertainties and geological uncertainties on Discrete Fracture Network (DFN). Several surface/controllable parameters have been considered for the Risk analysis evaluation on Plateau Length hypothesis and Recovery Factor.
The risk analysis accounts for two main recovery mechanisms: gas injection from the crest for Gas gravity drainage and periphery down dip water injection with imbibition.
Several scenarios of DFN's and 43 uncertain reservoir parameters with probability distribution were considered.
Experimental Design and Response Surface Methodology have been extensively applied to minimize the number of Reservoir simulation runs of the study.
Plackett and Burman Experimental Design has been used for the Screening Phase. During the screening phase, it has been revealed that 7 uncertain parameters account for more than 80 % of the total variation of Cumulative Oil Production.
A detailed Latin Hypercube has been performed with 3 discrete fracture network, controllable uncertain parameters and these 7 most relevant parameters.
This risk analysis identified the best cases of each phase of the development, P10 and P90, and the major uncertainties impacting the field development plan. Mitigation, acquisition and monitoring plan have been defined accordingly to reduce the major impacting uncertainties.
Computer Assisted History Matching - A Field Example
Authors: Lind R. H. , Allottai O. , Gaaim A. M. , Almuallim H. 
Published: September 2013

Abstract
Computer assisted history matching has received much interest in the recent past. Several commercial programs are now available. We have tested some of these programs – most did not meet our expectations and we discontinued using them.
The latest software tested helps in fine-tuning individual well behavior in a simulation model that has been globally matched. The program identifies model cells which have the highest influence on individual well behavior and modifies permeability in three directions (and porosity) such that the match is improved. Maximum allowed changes of permeability (and porosity) are controlled by the user. The procedure is repeated 10 to 20+ times until the match is considered satisfactory or the model no longer improves.
A flow simulation model is globally matched when all wells can flow historical rates, the pressure history in different compartments or layers can be reproduced, external aquifer properties are adjusted, and fluid and rock properties are verified. In such a model computed well watercut can be grossly in error, some wells are too high others too low. Manual fine-tuning of individual well behavior is a lengthy and frustrating process. We have tested the new computer assisted history matching program on several models. Improvements to most well matches were spectacular.
Model set up and history match procedures used are outlined on a moderately complex reservoir containing more than 1 billion STB oil initially in place. Production history spans 14 years, current recovery is ~25% of OOIP. Some 40 wells are active, four of them peripheral injectors. Injection voidage replacement is ~30%; there is a strong bottom and edge aquifer. The reservoir consists of 3 geological layers; the upper one has a permeability of several Darcy; the middle layer is highly heterogeneous and forms a partial seal to the lower layer with permeability of ~100 mD. We show examples of individual well matches before and after computer assisted fine tuning. We also discuss limitations of the program used and manual interferences required for selected wells.
Determination of Waterflooding Residual Oil Saturation for Mixed to Oil-Wet Carbonate Reservoir and its Impact on EOR
Authors: Masalmeh S. K 
Published: September 2013

Abstract
It is widely recognized that the determination of the amount and distribution of residual oil saturation (Sorw) is a significant factor in managing ongoing waterflooding and the selection of EOR methods that are applicable and economically suitable for oil reservoirs. Laboratory core flooding tests are often used to estimate the amount of Sorw. The same core samples are then usually subjected to EOR flooding experiments to estimate the extra amount of oil that can be recovered with the specific EOR option. Failure to accurately determine Sorw will lead to wrong estimates of recovery factor of both waterflooding and the subsequent EOR methods.
Significant amount of data is available in the literature on determining Sorw and on the critical capillary or bond number to mobilize Sorw. However, most of the data are measured on sandstone rock and for water-wet conditions. In this study the focus is on 1- determination of Sorw in the laboratory for carbonate reservoirs, 2- The factors that affect Sorw, including capillary end effect, capillary and Bond numbers, initial oil saturation, rock permeability, rock heterogeneity and experimental techniques and 3- The use of numerical simulation as tool to aid proper interpretation of laboratory experiments.
The main conclusions of the study are: 1- Performing the water flooding experiments at reservoir rates of ~1 ft/d will lead to overestimation of Sorw as the data can be dominated by capillary end effect; 2- The relative contribution of capillary end effect increases as the permeability increases especially for heterogeneous carbonate rocks; 3- There is no correlation between Sorw and rock permeability or porosity for the case understudy; 4- The critical capillary or bond number of non-water-wet carbonates is much higher than those reported in the literature for water-wet sandstone; thus experiments can be performed at higher rates than those expected in the field without the risk of de-saturation of Sorw and 5- Once an equilibrium between capillary and viscous (or gravity) forces is established, the remaining oil saturation is independent of the number of pore volumes injected.
The data presented in this paper has significant impact on the design of any subsequent EOR process. It shows that the EOR target (after waterflood) is significantly reduced if the measurements are performed using high rates (or high centrifuge speed) to overcome capillary end effect. Moreover, for non-water wet rock surfactant flooding will require much higher reduction in IFT to mobilize residual oil saturation than for water-wet rocks.
Coupled Geomechanical and Reactive Geochemical Model for Fluid and Heat Flow: Application for Enhanced Geothermal Reservoir
Authors: Xiong Yi , Fakcharoenphol Perapon , Winterfeld Philip , Zhang Ronglei , Wu Yu-Shu 
Published: September 2013

Abstract
A major concern in development of fractured reservoirs in Enhanced Geothermal Systems (EGS) is to achieve and maintain adequate injectivity, while avoiding short-circuiting flow paths. The injection performance and flow paths are dominated by the permeability distribution of fracture network for EGS reservoirs. The evolution of reservoir permeability can be affected by rock deformation, induced by the change in temperature or pressure around the injector, and chemical reactions between injection fluid and reservoir rock minerals. Thus the change in permeability due to geomechanical deformation and mineral precipitation/dissolution could have a major impact on reservoir long-term performance. A coupled thermal-hydrological-mechanical-chemical (THMC) model is in general necessary to examine the reservoir behavior in EGS.
This paper presents a numerical model, TOUGH2-EGS, for simulating coupled THMC processes in enhanced geothermal reservoirs. This simulator is built by coupling mean stress calculation and reactive geochemistry into the existing framework of TOUGH2 (Pruess et al., 1999) and TOUGHREACT (Xu et al., 2004a), the well-established numerical simulators for geothermal reservoir simulation. The geomechanical model is fully-coupled as mean stress equations are solved simultaneously with fluid and heat flow equations. After solution of the fluid, heat, and stress equations, the flow velocity and phase saturations are used for reactive geochemical transport simulation in order to sequentially couple reactive geochemistry at each time step.
We perform coupled THMC simulations to examine a prototypical EGS reservoir for permeability evolution at the vicinity of the injection well. The simulation results demonstrate the strong influence of rock deformation effects in the short and intermediate term, and long-term influence of chemical effects. It is observed that the permeability enhancement by thermal-mechanical effect can be counteracted by the chemical precipitation of minerals, initially dissolved into the low temperature injected water. We analyze the sensitivity of temperature of injected water on the coupled geomechanical and geochemical effects, and conclude that the temperature of injected water could be modified to maintain or even enhance the reservoir permeability and the injection performance.
Compositional Phase Trapping in CO2 WAG Simulation
Authors: Brown J. S. , Al-Kobaisi M. S. , Kazemi H. 
Published: September 2013

Abstract
A three-dimensional, three-phase, parallel compositional simulator has been developed to handle large computational efforts involving carbon dioxide (CO2) water-alternating-gas (WAG) injection. Algorithms have been developed to calculate three-phase relative permeability and capillary pressure, including the effects of phase trapping and relative permeability hysteresis for use in the simulator.
Injecting CO2 in oil reservoirs has two advantages: increasing oil production by miscible and immiscible displacement and sequestering CO2 as an environmental measure. Typically a WAG injection scheme is used to control the mobility of the injected fluids. Reservoir simulation models allow us to predict the future performance of CO2 enhanced oil recovery (EOR) and sequestration projects which are of high interest in the Middle East and throughout the world. Test cases applicable to Abu Dhabi carbonate reservoirs were simulated.
It is important to correctly account for trapped oil, water, and gas in reservoir simulation models. An incorrect estimate of trapped fluids in a sequestration project leads to over- or under-estimation of the CO2 stored in the reservoir. An incorrect estimate of trapped fluids in an EOR project leads to over- or under-estimation of CO2 required and inaccurate timing and amount of incremental oil recovery.
Industry simulators assume that mobile and trapped oil and gas in a grid cell are in thermodynamic equilibrium while in this model they are not. The formulation presented in this paper allows tracking the changes in composition of the trapped and mobile fluids during different WAG cycles.