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Collaborating Authors
Reservoir Description and Dynamics
Abstract Determining the optimum location of wells during waterflooding contributes significantly to efficient reservoir management. Often, Voidage Replacement Ratio (VRR) and Net Present Value (NPV) are used as indicators of performance of waterflood projects. In addition, VRR is used by regulatory and environmental agencies as a means of monitoring the impact of field development activities on the environment while NPV is used by investors as a measure of profitability of oil and gas projects. Over the years, well placement optimization has been done mainly to increase the NPV. However, regulatory measures call for operators to maintain a VRR of one (or close to one) during waterflooding. A multiobjective approach incorporating NPV and VRR is proposed for solving the well placement optimization problem. We present the use of both NPV and VRR as objective functions in the determination of optimal location of wells. The combination of these two in a multiobjective optimization framework proves to be useful in identifying the trade-offs between the quest for high profitability of investment in oil and gas projects and the desire to satisfy regulatory and environmental requirements. We conducted the search for optimum well locations in three phases. In the first phase, only the NPV was used as the objective function. The second phase has the VRR as the sole objective function. In the third phase, the objective function was a weighted sum of the NPV and the VRR. A set of four weights were used in the third phase to describe the relative importance of the NPV and the VRR and a comparison of how these weights affect the optimized NPV and VRR values is provided. We applied the method to determine the optimum placement of wells using two sample reservoirs: one with a distributed permeability field and the other, a channel reservoir with four facies. Two evolutionary-type algorithms: the covariance matrix adaptation evolutionary strategy (CMA-ES) and differential evolution (DE), were used to solve the optimization problem. Significantly, the method illustrates the trade-off between maximizing the NPV and optimizing the VRR. It calls the attention of both investors and regulatory agencies to the need to consider the financial aspect (NPV) and the environmental aspect (VRR) of waterflooding during secondary oil recovery projects. The multiobjective optimization approach meets the economic needs of investors and the regulatory requirements of government and environmental agencies. This approach gives a realistic NPV estimation for companies operating in jurisdiction with requirement for meeting a VRR of one.
- Asia > Middle East (0.46)
- North America > United States (0.46)
- Europe > Austria (0.28)
Abstract Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation. This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm. A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation. Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations. The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWise ED-XRF instrument at wellsite.
- North America (1.00)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") (0.41)
- Asia > Middle East > Kuwait > Ahmadi Governorate (0.41)
- Geology > Geological Subdiscipline > Stratigraphy > Chemostratigraphy (0.91)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.72)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.91)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (0.87)
ABSTRACT This paper presents a method for determining the Archie saturation exponent, n, from a single, nonequilibrium centrifuge step. The input measurements include detailed 3D saturation distributions from magnetic resonance imaging and the DC conductivity of the sample under examination. The latter is obtained by making use of a patented 4-contact cell. The sample is modeled as a 3D conductivity network and a specially developed algorithm based on random walk (RW) is used to compute its overall conductivity in a very short time. The value of the n exponent is determined by matching the measured conductivity to the calculated one. The entire analysis takes one day. Examples demonstrate the method and details of the impedance cell and the RW algorithm are provided.
Abstract Numerical reservoir models are used to predict, optimise and improve production performance of the oil and gas reservoirs. History matching is required to calibrate reservoir models to dynamic behaviour of the reservoir. On the one hand, historymatching does not have a unique solution and multiple models can fit observation data, on the other hand, history-matching is a tedious and time-consuming trial and error process as it involves numerous reservoir simulation runs. Modern history matching techniques use optimisation algorithms aim at providing a set of good fitting models in an efficient time. Many optimisation algorithms are applied in history-matching. Of them, Evolutionary Algorithms (EAs), inspired by natural evolution, do not use gradient information from the optimisation problem and only require the fitness function, usually defined as the sum of squares root deviation of model response from the observation data. Estimation of distribution algorithms (EDAs) are a novel class of EAs developed as a natural alternative to genetic algorithms in the last decade. To date, many EDAs are introduced which differ in the probabilistic model that guides the search process. Most of the EDAs are designed for discrete problems and require discretisation of search space when used for continuous problems, e.g. in history matching. In some cases, discretization error can be significant and deteriorate the search process. Gaussian-based EDAs use characteristics of Gaussian distribution for multivariate continuous problems. i.e. they make use of mean and covariance matrix of the variables in the promising solutions to generate new solutions which fit better the observation data. In this paper, we introduce and for the first time apply four Gaussian-based EDAs to assisted historymatching of a standard synthetic case. We show our proposed algorithms may produce results more accurately and more efficiently for the continuous problems.
- North America > United States (1.00)
- Europe (1.00)
- Asia (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Evolutionary Systems (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.47)
SUMMARY A method for obtaining porosity and fluid saturation distributions by inverting electromagnetic (EM) and seismic measurements is extended to three-dimensional (3D) geometries. For seismic modeling, we use the acoustic approximation. As demonstrated in the literature, the joint inversion of EM and seismic data reduces the non-uniqueness problem of determining porosity and saturation distributions. As the inversion algorithm we employ the preconditioned nonlinear conjugate gradient method and an alternating minimization scheme. The inversion algorithm is parallelized by using the message passing interface (MPI) library. Application of the algorithm on a 3D surface prospecting problem demonstrates that the method is able to simultaneously estimate porosity and fluid saturation distributions of the subsurface.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Cross-Correlation-Function Method for Separation of Shear Waves S1 and S2 in Azimuthally Anisotropic Media and an Example of its Application with Real Data
Chichinina, T. (Instituto Mexicano del Petroleo) | Obolentseva, I. (Trofimuk Institute of Petroleum Geology and Geophysics SB RAS) | Gorshkalev, S. (Trofimuk Institute of Petroleum Geology and Geophysics SB RAS) | Karsten, W. (Trofimuk Institute of Petroleum Geology and Geophysics SB RAS) | Korsunov, I. (Geostylus Limited)
ABSTRACT Summary We present a method for separation of the waves S1 and S2 in azimuthally anisotropic media. The method based on analysis of cross-correlation function is demonstrated by applying it to a real data from the Mexican Gulf.
- Asia > Russia (0.47)
- North America > Mexico > Gulf of Mexico (0.25)
- Asia > Middle East > Turkey > Selmo Field > S-2 Well (0.89)
- Asia > India > Andhra Pradesh > Bay of Bengal > Krishna-Godavari Basin > S1 Field (0.89)
Summary I compare different sets of solutions obtained with three stochastic algorithms to a highly multimodal inverse problem: the seismic to well tying of Time-Lapse Data. The problem is to find the perturbations of velocity and density in a layered model which explain the differences between the base and the monitor surveys. Several almost equivalent solutions exist especially if the thicknesses of the layers are thin. To explore the solution space I used three stochastic based optimizers: Simulated Annealing, Genetic Algorithms and Covariance Matrix Adaptation Evolution Strategy. In this paper, I compare the results obtained by the different algorithms not only in terms of speed and fitness but also in the way they offer the widest range of acceptable realizations.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (0.65)
Summary Synthetic ZTEM responses computed with 2D and 3D algorithms are compared. Excellent agreement is observed between 2D and 3D responses for structures with long strike lengths. Using the 2D inversion algorithm on synthetic 3D responses indicates artifacts being introduced when limited strike length is present: the conductivity of structures such as resistive hills and conductive structures is underestimated. Synthetic 3D models of a conductive target in a resistive host are used to demonstrate the effect of target strike length and target conductance on the ZTEM response. With an increase in strike length or conductance, the amplitude of the ZTEM responses increases. However, the amplitudes increase unevenly over the range of ZTEM frequencies. For low-conductance targets with short strike lengths the strongest responses are observed at the highest frequencies, whereas for high-conductance targets with long strike lengths the strongest responses are observed at the lowest frequencies. In the presence of a conductive overburden, responses are reduced by overburden blanking, but they can be boosted by current channeling if the conductor is in contact with the overburden. 2D and 3D inversion results of ZTEM survey data from Forrestania, Western Australia, show good agreement. The derivation of pseudo-profiles allowed for the 2D inversion of across-line data, which resulted in the modeling of structures not mapped by the in-line data.
Summary Information about seismic velocities is an important and integral part of the seismic imaging process. The task of defining the velocity model is usually quite difficult, especially in regions with a complex geological structure and in new prospecting areas. One emerging way of obtaining a velocity model is to apply a "velocity-less" prestack time migration to the data. Here we describe an application of the velocity-less prestack time migration technique to the real a dataset of a marine 2D seismic line from the North West shelf of Australia and show a comparison of the results with Kirchhoff prestack time migration. The presented algorithm is based on an estimation of local event slopes (horizontal slownesses) in common-shot and common-receiver gathers. These attributes allow us to derive the complete information to be able to construct a time migrated image. The output of the algorithm is three parameters: migration velocity, vertical traveltime and horizontal position of the migrated reflection point. Herein we use the obtained migration velocities as an input velocity model for the Kirchhoff time migration. This experiment on the real dataset demonstrates the promising practical effectiveness of the presented velocity-less prestack time migration algorithm.
Summary Porosity and pore aspect ratio are two important parameters for reservoir characterization of unconventional gas shales. Porosity estimation helps to determine gas capacity, as well as the bulk density of shales. The pore aspect ratio estimation helps to understand where the stiffest or softest intervals are, and along with density, more favorable for hydraulic fracturing. This work introduces an algorithm to estimate the porosity distribution and an algorithm to estimate the pore aspect ratio distribution of the Haynesville Shale. Both algorithms are based on the self-consistent model and a grid search method. For the porosity estimation, we first calibrated a specific self-consistent model that contains a representative composition assemblage and pore aspect ratio distribution. Then a grid search method was combined with this specific self-consistent model to generate a probabilistic estimation of porosity. The estimated porosity matched with the observed porosity. For the pore aspect ratio estimation, we first generated a group of self-consistent models that contained all plausible pore aspect ratios. Then a grid search based on P-impedance and porosity was applied to the self-consistent models and provided the matching pore aspect ratios. When seismic data from a 3D volume is involved, 3D distributions of porosity and pore aspect ratio can be characterized.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (0.74)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.70)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.30)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)