bluuebunny/crossref_metadata_2025_split huggingface dataset:
World's First Combination of Acid & Steam Provides A New Dimension To Heavy Oil Enhanced Recovery Process
Authors: Shaheen Tarek , Hassan Wael , Kamal Salah , Siddiqi Mohamed Irfan 
Published: June 2012

Abstract
The Issaran field located 200 km east of Cairo-Egypt, is a heavy oil reservoir. The oil is of 8–12 degree API with viscosity of 4000 cps at standard conditions.
Productivity of the wells has sharply declined due to increase in the water cut and increase in the formation skin value. The problem is attributed to the heterogeneity of the reservoir together with presence of fractures which is causing poor sweep efficiency plus the accumulation of hydrocarbon deposits.
The major challenge to remedy this situation was; 1) The creation of new extended flow channels. 2) Accurate placement of the treatment. 3) Diversion within the reservoir. 4) Provide sustain production increase. And 5) The flow and the production of oil through the newly formed wormholes.
A new innovative approach using a combination of acid based treating fluids and steam were used. Acid in combination with fit for purpose chemical diverting agent plus selective placement mechanism succeeded to open new production horizons and stimulate the existing one. The Addition of Steam has succeeded in reducing the viscosity and increasing the mobility of oil, and also in providing pressure support to the reservoir achieving further increase in the benefits of the acid stimulation.
The results of the treatments carried out so far have provided a new dimension in the enhanced recovery process of the heavy oil. This paper explains the design, execution, evaluation and the recommended way forward of this world first acid & steam production enhancement initiative for enhanced recovery process in the heavy oil reservoirs.
Optimization of Fluorinated Wettability Modifiers for Gas-Condensate Carbonate Reservoirs
Authors: Fahimpour J. , Jamiolahmady M. , Severac R. , Sohrabi M. 
Published: June 2012

Abstract
Significant reduction in well productivity of gas-condensate reservoirs occurs owing to reduced gas mobility arising from the presence of condensate/water liquid phases around the wellbore.
As wettability modifiers, fluorinated chemicals are capable of delivering a good level of oil and water repellency to the rock surface, making it intermediate gas-wet and alleviating such liquid blockage.
The main objective of this experimental work has been to propose an effective chemical treatment process for carbonate rocks, which have received much less attention in comparison to sandstone rocks. Screening tests, including contact angle measurements and compatibility tests with brine, were performed using mainly anionic and nonionic fluorosurfactants. On positively charged carbonate surfaces the anionic chemicals were sufficiently effective to repel the liquid phase, whilst the nonionic chemicals showed an excellent stability in brine media. A new approach of combining anionic and nonionic chemical agents is proposed, to benefit from these two positive features of an integrated chemical solution.
A number of low and high permeability carbonate cores have been successfully treated using chemicals selected through screening tests. Optimization of solvent composition and filtration of the solution before injecting chemicals into the core proved very effective in reducing/eliminating the risk of possible permeability damage due to deposition of large chemical aggregates on the rock surface. The chemical solution optimized in this study can be applied as an efficient wettability modifier for mitigating the negative impact of condensate/water banking in carbonate gas-condensate reservoirs.
Reservoir Description Of The Subsurface Eagle Ford Formation, Maverick Basin Area, South Texas, USA
Authors: Driskill Brian , Suurmeyer Nathan , Rilling-Hall Sarah , Govert Andrew , Garbowicz Amy 
Published: June 2012

Abstract
The Cretaceous Eagle Ford Formation (EF) is a marl deposited during a highstand on a broad shelf along the paleo-Texas coast. In south Texas, the EF is thickest in the Maverick Basin, which is a small sag related to crustal thinning. Extensive datasets were collected to use in subsurface studies that support exploration and development activities, including core, cuttings, chemostratigraphy, biostratigraphy, and well logs. Computed X-ray tomography (CT) scans, thin sections, scanning electron microscopy (SEM) images, focused ion beam-SEM (FIB-SEM) volumes, and X-ray diffraction/X-ray fluorescence (XRD/XRF) tables were acquired from whole core and cuttings. The goal of the integrated study was to understand EF depositional processes and rock textures, and to create a predictive model for reservoir properties.
The regional EF study began with a correlation of 400+ wireline logs. The correlation involved a stratigraphic framework that was initially based on log character, and was then refined with ash correlations, biostratigraphy data, and chemostratigraphy data. Textural information seen in core, core CT scans, and the SEM/FIB-SEM work was compared to the framework. The data gave insights into patterns of fluctuating oxygen and energy levels in the EF, which were then included into an idealized depositional model.
The datasets show regional patterns of composite cycles in which properties such as TOC, porosity, carbonate content, and rock texture are predictable. SEM/FIB-SEM images show that pores in the EF are mainly intergranular or within organic matter (OM), and that the structure of OM pores is related to maturity level. Reservoir properties can be predicted along the EF trend using the SF. Cycles of the EF with good reservoir properties can be mapped with respect to hydrocarbon fluid zones to yield risk maps.
Combining biostratigraphical, sedimentological, chemical, and physical properties is the key to understanding depositional cycles and cycle architecture. Geographic and stratigraphic sweet spots for well productivity can then be predicted by understanding how and where different parts of a cycle are stacked. As each unconventional play is unique, what works for reservoir characterization and risk mapping in one play is not necessarily applicable to another. However, developing an understanding of the interaction of the main reservoir properties should lead to less uncertainty, particularly in areas of the play with few existing wells.
Novel Insights into the Pore-Scale Mechanisms of Enhanced Oil Recovery by CO2 Injection
Authors: Sohrabi Mehran , Emadi Alireza 
Published: June 2012

Abstract
CO2 injection is a proven EOR (enhanced oil recovery) method, which has been extensively applied in the field. CO2 promotes oil recovery through a number of mechanisms including; CO2 dissolution, viscosity reduction, oil swelling, and extraction of light hydrocarbon components of crude oil. One of the main advantages considered for CO2 injection is that it can develop miscibility with most of light crude oils at a pressure lower than what would be required for other gases. Miscibility development is a function of reservoir pressure, temperature and also oil composition. In water flooded oil reservoirs, water can adversely affect the performance of CO2 injection as it reduces the contact between oil and CO2. However, CO2 will be able to dissolve into water and diffuse from water into the oil. The dynamic interplay between these various mechanisms is complicated and cannot be captured by existing models and simulations.
In this paper we present the highlights of the results of a series of visualization (micromodel) experiments performed using three different crude oils. CO2 injection was carried out to investigate the pore-scale interactions between CO2, crude oil and water inside the porous medium under liquid, vapour and super-critical conditions. In particular, we reveal a new mechanism that can lead to the recovery of the disconnected oil ganglia that do not come to direct contact with injected CO2. Our results reveal that, under certain conditions, a new phase can be formed in trapped oil ganglia and grows in size and can eventually connect the ganglia to the flowing CO2 stream and lead to their production. The increase in the size of the new phase continues without limit as long as CO2 injection continues and is much more than what can be achieved by the swelling of the oil due to CO2 dissolution. In the injection strategies where CO2 injection is associated or followed by water injection, e.g. CO2-WAG or CO2-SWAG, formation of the new phase can also divert the flow of water towards the unswept regions of the porous media and lead to additional oil recovery.
Integrated Interpretation for Pressure Transient Tests in Discretely Fractured Reservoirs
Authors: Morton K. L. , Nogueira P. de , Booth R. J. , Kuchuk F. J. 
Published: June 2012

Abstract
In this paper, we present the interpretation of pressure transient well test data from discretely fractured reservoirs, where the fractures provide conduits for fluid flow and displacement, but where the fracture network is poorly connected. For this reason, dual porosity models such as Warren and Root’s formulation are not usually applicable. We first outline the gaps in the existing pressure transient well test interpretation methodology for these reservoirs, then we introduce two new techniques developed to address these gaps: 1) a reservoir model-based inversion technique for the identification of spatial variation in reservoir parameters from pressure transient data, and 2) a boundary-element method for determining the pressure transient behavior of the reservoir with arbitrarily distributed finite and/or infinite conductivity vertical fractures.
Using these two new techniques, we defined a new integrated interpretation methodology for reservoirs with discrete natural fractures and incorporating openhole log data, seismic, and the preliminary geological reservoir model. This is an important step in reconciling static and dynamic reservoir data to update the geological reservoir model with meaningful parameters. This methodology provides a direct means of calibrating the fracture model with the well test pressure and rate measurements- one of the few dynamic and deep-reading measurements for reservoir evaluation. Finally, we illustrated the use of the methodology, and demonstrated its robustness by using an example DST from a fractured carbonate reservoir in Campos Basin, Brazil. Results indicated the presence of discrete fractures close to and intersecting the well that do not form a connected fracture network.
Oilfield Scale Management in the Siri Asset: Paradigm Shift Due to the Use of Mixed PWRI / Seawater Injection
Authors: Mackay Eric , Jones Trevor , Ginty Bill 
Published: June 2012

Abstract
There may be various drivers to implement Produced Water Re-Injection (PWRI). However, re-injecting produced water from the same field cannot replace the voidage created by production, especially early in the life of the field, since most of that voidage is created by hydrocarbon extraction. Thus seawater may have to be considered to "top up" PWRI. This raises the question of what are the implications for scale control of mixing potentially incompatible brines before injection, compared to the conventional injection scenario where the mixing takes place in the reservoir.
A study was set up to consider scale management during the life cycle of four offshore fields. The available data included analysis of formation and produced water and seawater compositions, and the time evolution of the produced water – seawater split in the injection system. The tools used included thermodynamic scale prediction and reservoir simulation calculations. Thus the evolution of the scale risk over the entire water cycle – from injection, through the reservoir, to production could be evaluated.
The produced water compositions and the results of the calculations show that the scale risk at the producers is much lower than if only seawater had been injected. Calculations were also performed to identify whether bullhead application of scale inhibitor would provide adequate protection for the wells. This was important, as some of the wells are subsea completions. The clear conclusion was that any residual scale risk at the producer wells could be managed by bullhead squeezing.
However, the corollary is that the scale risk at the injectors is much higher. The trigger for scale precipitation in this scenario is brine mixing, but instead of that happening in the reservoir, here it occurs before injection. Thus the location of greatest scale risk is moved much further upstream in the flow process.
Data-driven Monte Carlo Simulations in Estimating the Stimulated Reservoir Volume (SRV) by Hydraulic Fracturing Treatments
Authors: Qin G. , Chen R. , Gong B. , Xu B. 
Published: June 2012

Abstract
Hydraulic fracturing treatment has been proven to be the key factor for shale gas to flow at economic rate. Micro-seismic mapping has shown the extreme complexity of the hydraulic fracture network after the stimulation due to the geological complexity of shale formations. It becomes vitally important to understand the impact of the hydraulic fracture treatment, especially the massive multistage, multi-cluster hydraulic fracturing stimulations, to optimize stimulation and development plans of shale gas reservoirs.
Recent advances in micro-seismic mapping enable realistic modeling of hydraulic fracture network, though with significant uncertainty. Consequently, it is possible, to certain extent, to represent actual large-scale fracture distribution in reservoir modeling and simulation of shale gas development. In this paper, we propose a simulation method that is able to generate highly likely realizations of fracture network based on micro-seismic data, taking into account of data and shale formation uncertainty. The simulated realizations are then used to construct highly constrained unstructured gridding and a connection list of all neighboring cells (SPE 143590), using the Discrete Fracture Modeling (DFM) approach. DFM enables the prediction of production yield curve. With real production data, statistical analysis is done to calibrate and refine the simulation attributes. Based on a well calibrated simulation system, and linking initial hydraulic stimulation, induced fracture network and production data, we predict future stimulated reservoir volume and production yield curve, hence enabling the optimization of stimulation and development.
The proposed approach is extremely computational intensive. Approximations, efficient implementation and parallelization are used to make the approach practical. The approach was tested with success on real field experiments and data and the numerical results have shown great potential of the proposed approach to better understand the impact of hydraulic fracturing treatment.
Regularization in History Matching Using Multi-Objective Genetic Algorithm and Bayesian Framework
Authors: Sayyafzadeh Mohammad , Haghighi Manouchehr , Carter Jonathan N. 
Published: June 2012

Abstract
The history matching procedure can be divided into three sections: decision variables definition, objective function formulation and optimization. The most widespread approach regarding objective function formulation is the Bayesian framework. A Bayesian framework allows the incorporation of prior knowledge into the objective function which acts as a regularization method. In this approach, objective function consists of two terms; likelihood and prior knowledge functions. In order to maximize posterior probability function, usually a summation of prior and likelihood functions is minimized in which the prior and observed data covariance matrixes relate these two functions.
Inappropriate covariance matrixes can lead to an incorrect domination of one of the functions over the other one and accordingly result in a false optimum point. In this study, to decrease the chance of convergence into a false optimum point, due to inaccurate covariance matrixes, an application of multi-objective optimization in history matching is introduced while likelihood and prior functions are the two objective functions.
By making use of Pareto optimization (multi-objective optimization), a set of solutions named the Pareto front is provided which consists of nondominated solutions. Hence, an inaccuracy in the covariance matrixes cannot allow one objective function to dominate over the other one. After providing the set of solutions, usually a number of solutions are taken out from the set based on postoptimzation trade-offs for uncertainty analysis purposes.
For this study, a synthetic case is constructed and history matching is carried out with two different approaches; the conventional and the proposed approach. In order to compare the approaches, it is assumed that covariance matrix of the observed data is not exactly known. Then, history matching is carried out, using a single objective genetic algorithm with different covariance matrixes and also, using a multi-objective genetic algorithm. A comparison between the outcomes of the conventional approach and the proposed approach demonstrates that decisions can be made with more confidence using the proposed approach.
Geology and Geohistory Contribute to Flow Assurance
Authors: Hideharu Yonebayashi , Slavko Tosic , Dennis R. O’Brien 
Published: June 2012

Abstract
Kashagan is a super giant offshore carbonate field which was discovered in 2000 by a consortium of oil companies (currently, affiliates of): ExxonMobil, ENI, Shell, TOTAL, Conoco-Phillips, INPEX and KazMunaiGaz. The field is located in an environmentally sensitive area of the North Caspian Sea. The field is a deep, large structural relief, over pressured, isolated, carbonate build-up with a high-permeability, karstified and fractured rim and relatively low-permeability platform interior. The field contains a sour, undersaturated light oil with a large gas content. High pressure miscible gas injection is planned for oil recovery enhancement, as well as sulfur management.
No-one doubts the importance of flow assurance in offshore projects in particular. Moreover, it is now well known that gas injection operations require the evaluation of asphaltene deposition risk. The consortium has undertaken extensive evaluations to ascertain the likelihood of any flow assurance risks from subsurface to surface. During the asphaltene risk evaluation, many bottomhole samples have been collected and analyzed for asphaltene content, asphaltene onset pressure (AOP), and SARA (saturates, aromatics, resins and asphaltenes). These continuous analysis efforts have revealed some anomalous results such as AOP being detected from some fluid samples while not being detected from others.
The apparently inconsistent AOP results are critical to understand how to guide flow assurance measures. Therefore, all available asphaltene data were re-assessed in all their aspects to attempt to clarify asphaltene risk. This paper presents a multidisciplinary approach where a synergy between reservoir engineering and geoscience (geology and geohistory) has been developed to explain AOP results for this complex fluid. The results should help flow assurance specialists to better define the asphaltene operating envelope, which will be used for reservoir and production operations optimization. In addition, these results should be useful for optimizing data-surveillance, flow assurance, and for defining new sample acquisition plans. These findings may also be helpful to minimize future sampling and fluids analysis while achieving reliable flow assurance. The paper will show examples of the related flow assurance analyses, and the geological information which were incorporated in the study, resulting in a detailed asphaltene matrix risk profile for this reservoir.
Sorption of CO2 in Shales Using the Manometric Set-up
Authors: Khosrokhavar Roozbeh , Schoemaker Christiaan , Battistutta Elisa , Wolf Karl-Heinz , Bruining Hans 
Published: June 2012

Abstract
In a transition period from a fossil fuel based society to a sustainable energy society it is expected that CO2 capture and subsequent sequestration (CCS) in geological formations will play a major role in reducing greenhouse gas emissions. Possibilities of sequestration include storage in aquifers and depleted gas reservoir. The storage capacity of gas reservoirs for CO2 depends also on the sorption in the omnipresent minerals and shales. It is important to investigate whether adsorption on shales gives an important contribution to the storage capacity. It is also important to relate the adsorption to the carbon content in the shale. Only a few measurements have been reported in the literature for high-pressure gas sorption on shales, and interest is largely focused on shales occurring outside Europe. We present results using a high pressure manometric setup on a dried black shale sample from Belgium. It consists of more than 57% of clay minerals and 6.58% organic matter. The excess sorption isotherm shows an initial increase to a maximum value of 0.19 mmol/gram and then starts to decrease until it becomes zero at 82 bar and subsequently the excess sorption becomes negative. Similar behavior was also observed for other shales and coal reported in the literature.
We derive the equation for excess sorption in the manometric set-up allowing for a changing void volume. This equation is based on the finite density of the adsorbed phase. However, this is not the only mechanism causing a maximum in the sorption curve. Other reasons for void volume change are swelling of the shale and volume changes due to chemical reactions excluding sorption. Further research is necessary to investigate reasons for void volume changes in shales.
A Screening Process for Shale Gas Prospecting
Authors: Bérard T. , Liu Q. , Dubost F.-X. , Jing B. 
Published: June 2012

Abstract
While North American shale gas recovery efforts are booming, Europe and other parts of the world are just entering the game. The first main hurdle for operators today is to decide if and where to plant a flag in these vast and essentially uncharted territories. This paper presents a process developed to support exploration teams in the screening and ranking of shale play candidates. It is based on the Analytical Hierarchy Process methodology. The decision problem is first broken down into a treelike structure, or hierarchy, of controlling criteria. These criteria can relate to any aspect of the decision—tangible or intangible, accurately or roughly estimated, quantitative or qualitative. They are weighted as a function of their relative importance in meeting the set goal. Secondly, the candidates are scored according to how well they fulfil the criteria. Finally, these evaluations are converted into overall ranks, enabling straightforward comparison of the various courses of action. The sensitivity to both weights and scores is assessed to capture the impact on rank of uncertainty in criterion importance or in supporting data. The methodology is implemented in a software application. A hierarchy is proposed for shale gas play prospecting that considers as root criteria the resource—amount of gas in place, drilling and completion risks— as well as the commercial, regulatory, and operational/environmental contexts. Relative weights are assigned based on North American experience. For illustration purposes, a selection of plays in Europe and North Africa are then canvassed, and results are presented and discussed. The proposed criteria and weights can be fully customised to honour stakeholders’ objectives and suit the focus of the current exploratory phase (from the high-level screening of sedimentary basins to comparative analysis of economic conditions at country level to in-depth reconnaissance of "sweet" spots within a play).