bluuebunny/crossref_metadata_2025 huggingface dataset:
On Population Diversity Measures of the Evolutionary Algorithms used in History Matching
Authors: Abdollahzadeh Asaad , Reynolds Alan , Christie Mike , Corne David , Williams Glyn , Davies Brian
Published: June 2012

In history matching, the aim is to generate multiple good-enough history-matched models with a limited number of simulations which will be used to efficiently predict reservoir performance. History matching is the process of the conditioning reservoir model to the observation data; is mathematically ill-posed, inverse problem and has no unique solution and several good solutions may occur.

Numerous evolutionary algorithms are applied to history matching which operate differently in terms of population diversity in the search space throughout the evolution. Even different flavours of an algorithm behave differently and different values of an algorithm's control parameters result in different levels of diversity. These behaviours vary from explorative to exploitative.

The need to measure population diversity arises from two bases. On the one hand maintaining population diversity in evolutionary algorithms is essential to detect and sample good history-matched ensemble models in parameter search space. On the other hand, since the objective function evaluations in history matching are computationally expensive, algorithms with fewer total number of reservoir simulations in result of a better convergence are much more favourable. Maintaining population's diversity is crucial for sampling algorithm to avoid premature convergence toward local optima and achieve a better match quality.

In this paper, we introduce and use two measures of the population diversity in both genotypic and phenotypic space to monitor and compare performance of the algorithms. These measures include an entropy-based diversity from the genotypic measures and a moment of inertia based diversity from the phenotypic measures.

The approach has been illustrated on a synthetic reservoir simulation model, PUNQ-S3, as well as on a real North Sea model with multiple wells. We demonstrate that introduced population diversity measures provide efficient criteria for tuning the control parameters of the population-based evolutionary algorithms as well as performance comparison of the different algorithms used in history matching.
Effect of Hot Water Injection on Sandstone Permeability: An Analysis of Experimental Literature
Authors: Rosenbrand Esther , Fabricius Ida Lykke
Published: June 2012

The seasonal imbalance between supply and demand of renewable energy requires temporary storage, which can be achieved by hot water injection in warm aquifers. This requires that the permeability and porosity of the aquifer are not reduced significantly by heating.

We present an overview of published results regarding the effect of temperature on sandstone permeability. These tests are performed with mineral oil, nitrogen gas, distilled water and solutions of NaCl, KCl, CaCl2 as well as brines that contain a mixture of salts. Thirteen sandstone formations, ranging from quartz arenites to formations with a significant fraction of fine particles including clay minerals are investigated. The porosities range from 0.10 to 0.30 and permeabilities span the range from 1 to 1000 md. To compare different rock types, specific surface is determined from permeability and porosity using Kozeny's equation.

Heating causes thermal expansion, which results in porosity reduction if the sandstone is confined. The maximum effect of porosity reduction as a result of thermal expansion on permeability is modelled and compared the change in specific surface that is computed from the reported data. This does not account for all the permeability reductions observed.

Permeablity reduction occurs both when distilled water is the saturating fluid as well as in tests with NaCl, KCl or CaCl2 solutions, however, this is not the case in tests with mineral oil or nitrogen gas. The formation of a filter cake or influx of colloidal particles due to corrosion of the apparatus at elevated temperature causes permeability reduction in a number of investigations. Mobilisation of internal particles, particularly kaolinite particles, is considered a probable mechanism of permeability reduction for the other experiments reviewed here.

The parameters that strongly affect the success of heat storage therefore include the quality of the equipment and particularly the prevention of corrosion, as well as the sandstone lithology and its interaction with the reservoir fluid.
Rock Physics Modeling of CO2 Bearing Reservoir Rocks
Authors: Hossain Zakir
Published: June 2012

CO2 capture and storage (CCS) is a technique to reduce CO2 emission, and CO2 is also used in EOR (enhanced oil recovery). It may increase oil production by 15–25% from an oil field. In this paper we present how to deal with the seismic response due to CO2 injection. To understand the seismic response due to CO2 flooding requires knowledge of the distribution of CO2 in brine, viscous loss due to CO2 and dissolution of CO2 in brine. Furthermore, the basic principle for EOR methods by CO2 is that high solubility of CO2 increases the density and lowers the viscosity at reservoir conditions of the oil, thus improving the oil mobility and the efficiency of water flooding. However, the viscous losses during the fluid flow are responsible for seismic wave attenuation. Moreover, when injecting CO2 into the water-saturated sample, some CO2 may be dissolved in the water. The Gassmann and Reuss or Gassmann and Voigt method may be used to calculate CO2 saturated seismic properties. Considering the significant differences between velocity values in these two methods, a large uncertainty is associated with fluid-saturation estimation from seismic data. I provided the rock physics model to calculate the CO2 saturated seismic properties to understand the seismic response due to the CO2 flooding. This model was tested laboratory measured data of sandstone from Lei and Xueb (2009) and carbonate from Wang et al. 1998. Modeling results provided us the viscous loss and dissolution of CO2 effects to calculate the CO2 saturated seismic properties. This model may be also used to calculate the accurate hydrocarbon production during the EOR method by CO2 injection.
Comparison of Upscaling Methods in a Heterogeneous Carbonate Model
Authors: Kazemi Alireza , Shaikhina Dana , Pickup Gillian , Corbett Patrick
Published: June 2012

Carbonate reservoirs are of great importance, due to their large hydrocarbon reserves. However, their complex structure makes them challenging targets to develop. In order to predict reservoir performance, we need to be able to model the effects of heterogeneity at a variety of scales. In this study, we have constructed a detailed geological model using published data for an outcrop in the San Andres Formation. The resolution of the model is 1.2 m × 0.6 m, much finer than a conventional reservoir simulation model. The aim of this work was to consider various upscaling methods and various modelling methods to understand the current limitations and challenges.

A number of single-phase upscaling methods were tested, including averaging (arithmetic/harmonic), and flow-based upscaling with local and extended boundary conditions. In addition the Well Drive Upscaling (WDU) method, a relatively new method, was applied. In this method a single-phase global simulation is performed with appropriate boundary conditions: high pressure at injection wells, low pressure at producers. The flows are then summed and the pressures averaged in order to calculate the effective transmissibilities between the coarse cells.

The upscaling methods were tested by simulating a waterflood. Cases with single and multiple relative permeabilities were examined. The upscaling factor in each case was 65 by 5. In general, the coarse-scale models gave late breakthrough, and overestimated the recovery. The WDU method was consistently better than the other methods, because it was able to preserve the correct flow between coarse cells. On the contrary, the conventional flow-based methods with local boundary conditions gave poor results, sometimes worse than averaging.

We then applied the WDU method to upscale various carbonate models that had been constructed using the Porosity Derived System approach (PODS). The results of this specific 2D study show that upscaling in a complex carbonate reservoir is feasible, providing a suitable method, such as the WDU method, is applied.
Assisted Seismic History Matching in Different Domains: What Seismic Data Should We Compare?
Authors: Sagitov Ildar , Stephen Karl D.
Published: June 2012

Time-lapse (4D) seismic data can be integrated into history matching by comparing predicted and observed data in various domains. These include the time domain (time traces), seismic attributes, or petro-elastic properties such as acoustic impedance. Each domain requires different modelling methods and assumptions as well as data handling workflows. The aim of this work is to investigate the degree to which the choice of domain influences theoutcome of history matching on the choice of best model and associated uncertainties. Another aspect of history matching is that long simulations often pose an obstacle for an automatic approach. In this study we use appropriately upscaled models manageable in the automatic history matching loop.

We apply manual and assisted seismic history matching to the Schiehallion field. In the assisted approach, the optimization loop is driven by a stochastic algorithm, while the manual workflow is based on a qualitative comparison of 4D seismic maps. By upscaling we obtained an order of magnitude gain in performance. Accurate upscaling was ensured by thorough volume and transmissibility calculation within regions. The parameterisation of the problem is based on a pattern of seismically derived geobodies with specified transmissibility multipliers between the regions. Seismic predictions are made through petro-elastic modelling, 1D convolution, coloured inversion and calculation of different attributes.

We were able to achieve a reasonable match of production and 4D seismic data using coarse scale models in manual and assisted approaches. We observed that the misfit surfaces are different when working in the various seismic domains considered. Use of equivalent domains for observed and predicted data was found to give a more unique misfit response and better result.

Accurate comparison of predicted and observed 4D seismic data in different domains is necessary for tackling non-uniqueness of the inverse problem and hence reducing the uncertainty of field development predictions.
Smart Waterflooding (High Sal/Low Sal) in Carbonate Reservoirs
Authors: Zahid Adeel , Stenby Erling H. , Shapiro Alexander A.
Published: June 2012

In the last decade, high salinity waterflooding has been emerged as a prospective EOR method for chalk reservoirs. Most recently, Saudi Aramco reported significant increase in oil recovery by low salinity waterflooding in Saudi Arabian carbonate reservoirs. Understanding of the mechanisms leading to an increase in oil recovery in both smart waterflooding processes (low and high salinity waterflooding) is still not clear. In this paper, we investigate experimentally the recovery mechanisms for both methods.

To understand high salinity waterflooding process, we studied crude oil/seawater ions interaction at different temperatures, pressures and sulfate ion concentrations. For low salinity waterflooding, flooding experiments were carried out initially with the seawater, and afterwards the contribution to oil recovery was evaluated by sequential injection of various diluted versions of the seawater.

Our results show that sulfate ions may help decrease the crude oil viscosity when high salinity brine is contacted with oil under high temperature and pressure. We have also observed formation of an emulsion phase between high salinity brine and oil with the increase in sulfate ion concentration at high temperature and pressure. We propose that the decrease in viscosity and formation of an emulsion phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs, besides the mechanism of the rock wettability alteration, which has been reported in most previous studies.

No low salinity effect was observed for the reservoir carbonate core plug at the room temperature. On the contrary, a significant increase in oil recovery was observed under low salinity flooding of the reservoir carbonate core plugs at 90 °C. NMR measurements indicated that low salinity brines did not significantly change the surface relaxation of the carbonate rocks.

Migration of fines, dissolution and destruction of rock particles are possible mechanisms of oil recovery increment with low salinity brines from carbonate core plugs at 90 °C. At the present stage, the mechanisms behind increment in oil recovery under various conditions appear to be different.
Optimization of Proactive Control Valves of Producer and Injector Intelligent Wells under Economic Uncertainty
Authors: Sampaio M. A. , Barreto C. E. , Schiozer D. J.
Published: June 2012

Intelligent wells can improve oil recovery, mitigate risks and avoid unnecessary well intervention in petroleum fields. However, there is no consolidated methodology to evaluate the applicability of intelligent wells and to represent them in commercial simulators, which complicates the comparison with conventional wells. Moreover, there are two main modes of operation of intelligent well valves, reactive and proactive; each one can provide different benefits. In general, proactive control seeks maximum oil recovery, but it requires larger computational effort and greater knowledge of the reservoir than the reactive control. This paper presents a comparison between different configurations of intelligent wells with proactive control and mode operation on/off: (1) five-spot configuration with conventional wells (producer and injectors), (2) one intelligent producer and four conventional injectors, (3) one conventional producer and four intelligent injectors and (4) one intelligent producer and four intelligent injectors, in order to compare the different behaviors. The objective of this study is to evaluate the potential of proactive operation for each type of configuration and the benefits of the intelligent injectors and producer acting separately or together, considering the effects on production and costs of intelligent completion. For this, a genetic algorithm was coupled to a commercial simulator to optimize the proactive control and to search the maximum net present value (NPV), determining the optimum operation control for each valve. The case study consists of one heterogeneous reservoir model, light oil and three economic scenarios (pessimistic, probable and optimistic). Results show that the use of intelligent injector and producer wells together, in this case study, can increase of oil production and decrease of water production, although it may not be the most advantageous alternative because of the higher investment. On the other hand, the configuration using only an intelligent producer well (lower investment) is capable of increasing oil recovery sufficiently, therefore making the best investment with intelligent completion, in this case study.
An Engineering Approach to Utilize Fiber Optics Telemetry Enabled Coiled Tubing (ACTive Technology) in Well Testing and Sand Stone Matrix Stimulation - First Time in the World
Authors: Shaheen Tarek , El Rahman Sayed Abd , Anwar Emad , Dilling Lambert , Noya Vidal
Published: June 2012

For the last several years, viscous pills, polymer based, were used to kill the wells during the workover operation in the tronian formation existing in the eastern desert of Egypt. These polymer pills have negatively affected the wells productivity by blocking the pore throats and reducing the permeability. As an example, the well A-1 was producing 300 bpd (Gross) which declined dramatically after a workover operation which included the viscous polymer pills to produce only 20 bopd.

An engineering study was carried out to identify the main reason for the decline in the production. Several experiments were performed in the lab in order to simulate the filter cake using formation samples and evaluate the effect of the polymer being injected on the sandface permeability. An engineered solution was designed to break the polymer subsequently pumped in the formation and stimulate the matrix in order to recover and enhance the oil production. The remedial work was executed using a Fiber Optics Telemetry Enabled Coiled Tubing (FOTECT) system to optimize the treatment leveraging on downhole real time measurements.

This paper describes the first application of FOTECT in sandstone formations, involving:

The sandstone matrix stimulation operation. Measuring both bottom hole pressure and temperatures at static and dynamic conditions during the entire operation. Accurate depth correlation to achieve optimum placement of the treatment fluids Monitor the chemical reactions in real time of the engineered treatment fluid. Monitor the diversion performance during Sand Stone stimulations and the timing required for efficient reactions. Qualitative production allocation of the interval as a response to the treatment fluids Evaluation of the skin value real-time while executing matrix stimulation. Pressure transient analysis in real-time enabling the standard output of a well test (permeability, skin, Pressure, and reservoir boundaries).

The experience demonstrates that use of real-time downhole measurements during the CT treatment allows: a) the evaluation of the well performance before and after the treatment, b) enables optimization of the treatment as it is executed, based on the formation response, enhancing the chance for a successful intervention, and c) provides an added alternative to perform a well testing operation right after the treatment, thus, obtaining valuable information to update the reservoir model.
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

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

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

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

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

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

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

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

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

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

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

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).
Effects of Reservoir Parameters and Operational Design on the Prediction of SAGD Performance in Athabasca Oilsands
Authors: Nguyen Huy X. , Wisup Bae , Tran Xuan V. , Ta Dung Q. , Nguyen Danh H.
Published: June 2012

The efficiency of the SAGD process depends on two important factors: reservoir properties and operating conditions. SAGD performance was investigated based on the variables of reservoir properties such as thickness, porosity, permeability, oil saturation, viscosity, rock thermal conductivity, along with operating variables as including preheating, injector/producer spacing, injection pressure, steam injection rate and subcool temperature. In addition, the economic risks associate to the high capital and operation expenditures, and uncertainties of oil and gas prices in the market. In order to manage the uncertainties of oilsands project, we need the quantitative analysis of concerned parameters affecting returns. Then, we can propose optimization design for operating conditions.

The previous studies conducted sensitivity analysis and optimization of SAGD performance by classical methods. Therefore, there was a lack of confidence level because they did not determine the significance level of parameters and ignored interactions effects between considered parameters, lead to low efficiency issues in a field operation. Furthermore, the economic models were not comprehensive enough with limited consideration on few factors. These restrictions of classical method can be avoided by applying D-optimal design and response surface methodology to find the best regression model for SAGD performance.

There were a total of 75 cases for screening reservoir and operational parameters with the NPV responses based on the D-optimal design. The results showed that reservoir properties have a greatest influence on the SAGD performance with ranking order of porosity, thickness, oil saturation, permeability, viscosity, respectively. The optimization design of operating conditions obtained the maximum NPV when vertical well spacing 9m, injection pressure 5,000kPa.
New Flattening-Based Methodology for More Accurate Geostatistical Reservoir Populating
Authors: Poudret Mathieu , Bennis Chakib , Dumont Cyrielle , Lerat Olivier , Rainaud Jean-François
Published: June 2012

In the domain of oil exploration, geostatistical methods aim at simulating petrophysical properties in a 3D grid model of reservoir. The main input comes from drilled wells data in the geographic space. Lithofacies and petrophysical properties as porosity and permeability are measured along these wells trajectories. These data are then assigned to every cell of the 3D grid model which intersects a well trajectory. At this step, only a small amount of cells are populated with petrophysical properties. Roughly speaking, the question is: which properties we should give to cell c, knowing the properties of n cells at a given distance from c? Obviously, the population of the whole reservoir must be computed while respecting the spatial correlation distances between petrophysical properties. Thus, the computing of these correlation distances is a key feature of the geostatistical simulations.

In the classical geostatistical simulation workflow, the evaluation of the correlation distance is imprecise. Indeed, they are computed in a Cartesian simulation space which is not representative of the geometry of the reservoir. Thus, depending on the deformation degree of the lithostratigraphic units in the geographic space, significant errors may be introduced in the geostatistical simulation. This lack of accuracy has prompted us to work on and devise a new methodology in order to increase the reliability of the parameters required by the geostatistical simulators.

We propose a new methodology in order to better estimate the correlation distances between wells. Our methodology is based on the isometric flattening of lithostratigraphic units. Thanks to this flattening process, we accurately reposition the initial populated cells in a flat simulation space, before computing the correlation distances. In this paper, we introduce our methodology through study case representing different deposit modes of the sub-surface models. We finally present some preliminary results.
Vertical Lift Models Substantiated by Statfjord Field Data
Authors: Fevang Øivind , Fossmark Marthe Gilje , Nordaas Kulkarni Kari , Lauritsen Håvard Thomassen , Skjaeveland Svein M.
Published: June 2012

The Statfjord field entered into the blow down phase after 30 years of production. Production of injection gas and gas liberated from residual oil is the main production target in this phase. In some areas, the gas cap has been produced and the wells are producing mainly water until the solution gas is mobilized. These wells have gone through large changes in gas-liquid-ratio (GLR) and water-cut (WCT). Production tests from wells located in such areas have been used when analyzing the ability of multiphase-flow correlations to model vertical lift performance (VLP). Accurate modeling of the VLP is critical to predict a realistic production rate during the blow down phase.

Measured wellhead (THP) and downhole pressures from about 80 production tests, from four wells, were used to analyze the accuracy of VLP correlations at widely varying flow conditions (GLR, WCT, and THP). Altogether 17 multiphase pressure drop correlations incorporated in the program Prosper were tested by comparing observed and calculated downhole pressures.

Based on the production tests the ability of the different correlations to predict the VLP varies with the following top 4: Hagedorn Brown, Petroleum Experts, Petroleum Experts 2, and Petroleum Experts 3. These correlations are recommended if no measured data is available.

In general a somewhat low pressure drop is predicted at low gas-liquid ratio (GLR), and a somewhat high pressure drop is predicted at high GLR. After tuning, accurate predictability was observed for the different correlations for limited ranges in GLR e.g. 50-300 Sm3/Sm3. However, for larger ranges in GLR it was not possible to achieve an accurate VLP correlation, even after tuning. Hagedorn Brown and Petroleum experts seem to be the most accurate correlations for a wide range of producing GLR.

The error in the predicted production performance when a single VLP correlation is used can be substantial for highly productive wells with large variations in producing GLR. It is recommended to shift the tuning following the GLR development.