bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching by Online Metamodeling
Authors: Sayyafzadeh Mohammad 
Published: September 2015

Abstract
The high computational costs associated with reservoir simulation create a major barrier in history matching problems. Within the past decades, several efforts have been made to reduce CPU-time by metamodeling (proxy-modeling) techniques in which the original fitness function (OF) is partially or completely substituted by an approximation-function (AF), often called metamodel or surrogate. In order to build a high-fidelity surrogate, usually a large number of training samples is required. This can make the traditional surrogate-assisted algorithms, inefficient. In recent years, it has been shown that to approximate the global optimum using a surrogate-assisted algorithm, the AF does not necessarily need to be of high-fidelity, if it is applied in conjunction with the OF and retrained online, during the optimization process.
In order to use the OF effectively and minimally, a model-management strategy is required. In this study, a new adaptive model-management strategy is proposed, in which a second surrogate is required. The first surrogate approximates the original fitness function landscape, and the second one estimates the fidelity of the first surrogate over the search-space. On the basis of the estimated fidelity, a probability for employing the OF is calculated, and then according to the calculated probability, the algorithm stochastically decides to use the OF or the AF. A heuristic fuzzy rule is also applied to adjust the possible range of probability values in each evolution-cycle, based on the average fidelity of the second surrogate.
The robustness of the proposed algorithm is analyzed using different analytical benchmarking functions, and a semi-synthetic history matching problem, IC-fault model. To deliver a comparative study, the optimization is also carried out using three other algorithms, without metamodeling (OF-only), offline-learning (AF-only), and online metamodeling with a predefined and constant probability. The outcomes of all four algorithms are compared with each other. The assessment shows that the proposed method can reduce the computational costs significantly.
Integrated Numerical Simulation for a Giant, Asphaltene Riched, Carbonate Reservoir
Authors: Bingyu Ji , Peiqing Lian , Xuequn Tan , Taizhong Duan 
Published: September 2015

Abstract
Fah reservoir in Y oilfield is a giant, pore-typed, carbonate reservoir, which have high heterogeneity and asphaltene deposition during production process. In order to describe the heterogeneity of Fah reservoir, fomulas of pore throat radius, porosity and permeability under different mercury injection saturation was fitted. It shows 30% is the best percentile, and R30 method was presented for rock typing. Six rock types were divided according to pore throat radius, the porosity-permeability relationship was established for each rock type. The rock types of the non-cored wells are predicted by KNN (K nearest Neighbor) method. After the rock types of all wells have been obtained, 3D rock type model was built by sequential indicator simulation, and the 3D porosity could be established on the basis of the rock type model, logging interpretation and sesmic data. 3D permeability model was calculated according the relationship between porosity and permeability. Comparing core permeability and calculated permeability obtained by the rock types, it shown very good coincidency.
During the oilfield development process of Fah reservoir, the asphaltene deposition is very serious, which cause the production decline. Therefore, it is quite necessary to carry out the asphaltene deposition study. Based on the experiment research, the phase behavior of the asphaltene was studied, and the asphaltene precipitation envelope diagram was drawn on the basis of the gas-liquid-solid three-phase equilibrium theory. A fine numerical simulation model to simulate asphaltene precipitation, flocculation, deposition and damage processes was established, the impact of asphaltene on recovery was studied and the recovery of 10 years was declined by 2.3% in considering asphaltenes. By controlling the bottomhole pressure, the asphaltene precipitation in the formation could be prevented. In order to study the asphaltene depostion in the wellbore and the surface pipeline, a reservoir, wellbore and surface pipeline integrated model was built by coupling the Eclipse and IPM software together, and the pressure and temperature from reservoir to separator can be predicted, then compared with precipitation envelope diagram, the location of asphaltene precipitation could be determined accurately.
New Solution to Pressure Transient Equation in a Two-Layer Reservoir with Crossflow
Authors: Lu Jing , Zhou Botao , Rahman M. M. 
Published: September 2015

Abstract
A two-layer reservoir with crossflow was erroneously taken as a dual-porosity-dual-permeability naturally fractured reservoir in the literature, and the solutions obtained from dual-porosity-dual-permeability model cannot account for the characteristics of two-layer reservoir.
This paper presents a new mathematical model and an analytical solution to the pressure transient equation of a uniform-flux fully penetrating vertical well in a two-layer reservoir with crossflow. The pressure of a vertical well producing a two-layer reservoir with a constant rate is examined. The pressure response is observed in three stages: first, it is identical to the commingled system, because the crossflow is so weak at the production beginning that we can ignore it. Second stage is transition stage and the third stage, which is same as the homogeneous system. What's more important, we propose a parameter to describe the crossflow in a two-layer reservoir quantitatively. It is verified that the crossflow coefficient is not constant, but a function of the time and distance away from the wellbore.
These solutions are obtained by using Laplace transform, double Fourier transform and Green's functions method with numerical approximations. These solutions give results accurate enough for practical applications and allow to estimate the effects of formation properties on pressure behavior both at large distance from the wells and at the wells. When all the corresponding parameters are identical in each layer, the proposed solution for a two-layer reservoir reduces to the solution for a single layer reservoir.
The solution procedure proposed in this paper is a fast tool to evaluate a vertical well performance in a two-layer reservoir.
Production History of a Hetergenous Carbonate Reservoir Dictates New Factors to Optimize New Well Placement in a Miscible Gas Injection Field-a Case Study
Authors: Hashemi Abolfazl , Miri Bahram , Chegeni Reza , Namdarian Fatemeh , Taghanaki Morteza Aghababee , Karami Mehran 
Published: September 2015

Abstract
Defining in-fill drilling locations seems a simple task in natural depletion reservoirs while in special fields like those under miscible gas injection operation is challenging. The aim of this paper is to scrutinize the production and injection of existing wells and derive some extra rules to optimize the new well placement in miscible gas injection fields.
DGN is an undersaturated light oil field situated in south west of Iran. The field has been producing since 2003 and miscible gas injection started in 2009. After 5 years of miscible gas injection, unexpected and different types of breakthrough happened in some producing wells which made defining new well locations a challenging task. Gas injection has sweeping role as well as pressure maintenance, and based on studied reservoir heterogeneity the latter one was recognized as a dominant factor. After reviewing all available studies and static and dynamic models as well as real field production and welltesting data, some rules were extracted to narrow the window to some specific regions. Therefore, a new gas injection well was spotted on the anticline of the reservoir even close to other injection wells and five new locations were decided. Afterward, they were put into dynamic model and their production was compared. At the end, those wells with better performance were given higher priority and sent for drilling.
Considering recovery factor of the reservoir, it indicates that new gas injection well can have better performance on the crest of the reservoir even in the vicinity of the other injectors, and oil producing wells should be in symmetrical pattern, down-dip and farthest from injection wells.
A Miscible EOR Project in a Mature, Offshore, Carbonate Middle East Reservoir – Uncertainty Analysis With Proxy Models Based on Experimental Design of Reservoir Simulations
Authors: Bevillon Damien , Mohagerani Saeid 
Published: September 2015

Abstract
This paper presents the reservoir modeling and an improved engineering workflow to perform a technical evaluation of an EOR miscible hydrocarbon gas injection project using horizontal wells. This project was performed in the Fateh Mishrif, a large carbonate reservoir in a Middle East offshore operating environment. A new methodology to generate synthetic forecast of EOR oil and gas profiles is proposed. The paper describes the technical approach followed to assess the impact of uncertainties and the process used to carry them forward into a probabilistic uncertainty analysis.
Experimental Design and proxy model techniques with associated algorithms, uncertainties, bias, and accuracy vs. simulation models have been discussed through numerous papers. These papers usually present discrete results such as Cumulative oil, STOIIP, or NPV though proxy allowing a simple and time saving solution compared to resource consuming compositional simulations.
The new tool developed here allows for rapid re-computing of a full “synthetic” EOR oil and gas profile (or Response Function) build on 6 essential parameters (EOR breakthrough time, oil ramp up, peak oil, peak oil time, decline, cumulative oil), which are identified as the typical signatures of EOR oil and gas response to miscible gas injection. The EOR profiles are designed for patterns representing the Field Development Plan. The 6 parameters are individually computed through their own proxy models and are a function of 19 inputs parameters. Each proxy model is built based on Experimental Design simulations with Latin-hypercube method which runs hundreds of simulation cases based on the 19 uncertainty parameters. Iterations process with a sufficient number of runs ensures the reliability of the proxy model (Polynomial Regression) vs. simulations with minimizing error.
The response of EOR oil and gas can be predicted as a function of a range of uncertainty with parameters such as rock properties, PVT, as well as operational parameters such well performance, gas injection rate, and WAG management. A work based on lab data, simulation history match, and literature has been achieved for the description, selection, and settings of the boundary values of each parameter to minimize bias.
Response Functions are ready for roll up process for the EOR Field Development Plan through a spreadsheet and for decision making by use of uncertainty analysis.
Development and Validation of an Iteratively Coupled Geomechanics Module for a Compositional Reservoir Simulator, UTCOMP
Authors: Haddad Mahdi , Al-Shalabi Emad W. , Sepehrnoori Kamy 
Published: September 2015

Abstract
Pore pressure-stress analyses in stress-sensitive reservoirs investigate interactions between the in-situ stress and fluid flow; these interactions help or resist production, or conclude surface subsidence during production. Among the tools for these analyses, an iteratively coupled Geomechanics and fluid flow model provides an essential and reliable prediction for field planning and development. In this work, we implemented this model in an in-house, three dimensional, compositional reservoir simulator, UTCOMP, using modified Chin’s iterative coupling method. This development integrated a stand-alone Geomechanics module based on finite element method with the reservoir simulator, an advantage of our coupling algorithm, and improved our understanding of the production through various enhanced oil recovery processes such as water and CO2 floodings previously coded in UTCOMP. Benefiting from the higher time scales of solution variations due to the Geomchanics module, we lowered the frequency of calling this computationally expensive module. Also, we reduced the order of the finite element shape functions from quadratic to linear, which majorly mitigated the high computational cost of our Geomechanics studies while we almost maintained the solution accuracy. To validate our implementation, we investigated a primary oil production case and compared the results from UTCOMP with those from two other simulators: 1) CMG software program using different coupling methods; and 2) another pre-validated in-house reservoir simulator, GPAS. Moreover, due to the lack of real field data, we validated our solutions for the enhanced oil recovery problems by comparing them with those from GPAS coupled with Geomechanics. We observed a minor discrepancy between the solutions at very early times which originates from the different structures in these two reservoir simulators, IMPEC in UTCOMP and fully implicit in GPAS.
A Novel Approach for a Fast and Accurate Petrophysical Characterization of Carbonate Reservoirs Based on NMR
Authors: Pirrone M. , Bona N. 
Published: September 2015

Abstract
This paper discusses the use of a novel methodology for the petrophysical characterization of carbonate reservoirs. The methodology makes use of nuclear magnetic resonance (NMR) log and core data and provides direct and fast estimates of downhole porosity, pore size, petrophysical rock types, irreducible water saturation and permeability. The novelties of the approach lie on the developed permeability model and the critical role played by effective surface relaxivity. It is shown that if this parameter is properly defined, NMR logs do not need any additional calibration.
The methodology is demonstrated for a Cretaceous carbonate reservoir in the Middle East. A dataset comprised of NMR log acquired on one key well and special core analysis results from seven wells is utilized. Fifteen other wells are used as blind tests, once the model has been calibrated. Generalization to other carbonate reservoirs is then discussed.
In details, a pore size distribution predictor is defined, which makes use of a system built upon mercury injection measurements and is able to discriminate micropores, mesopores and macropores downhole. Making this categorization is fundamental for reservoir modeling purposes, fluid-flow behavior assessment and to understand wettability. Micropores are associated with bound fluids, so the aforementioned porosity partition supplies also an estimation of irreducible water saturation. The established link between NMR transverse relaxation time distributions and pore size distributions provides a direct estimation of NMR effective surface relaxivity, both at laboratory and reservoir conditions. This parameter is fundamental since it represents the main driver for the subsequent computation of permeability, by means of a new and advanced modeling. The overall good match between the entire NMR-based interpretation and core data demonstrates the reliability of the methodology.
Although several approaches exist to aid formation evaluation in carbonates based on quantifying rock texture by NMR, the quantitative use of effective surface relaxivity is relatively new and can shed new light on this topic.
Characterization of Coquinas and Dolomites Integrating Electrical Resistivity, Nuclear Magnetic Resonance (NMR) and Porosimetry by Mercury Intrusion (MICP)
Authors: Fiorelli G. L. , Winter A. , Koroishi E. T. , Trevisan O. V. 
Published: September 2015

Abstract
This study aims to characterize carbonate rocks outcrop with similar petrophysical properties of the Brazilian pre-salt by three different methodologies: Electrical Resistivity, Nuclear Magnetic Resonance (NMR) and Porosimetry by Mercury Intrusion (MICP) at room conditions. The rocks are coquinas from the Coqueiro Seco Formation at Sergipe Basin - Alagoas, Brazil, and Silurian dolomites from the Thornton formation, in United States. The rock samples were analyzed for varying brine / air / oil saturations by measuring electrical resistivity and magnetic transverse relaxation time (T2) at each level of saturation. Samples were also analyzed for throat size distribution using the technique of porosimetry by mercury intrusion (MICP). The relaxation time results show that the pore structures of the two carbonate rocks have pore size distributions of multimodal character. The coquinas and dolomites are composed mostly of macropores structures with a small fraction of micropores and mesopores. Nonetheless, the MICP results showed distinct distributions of pore throats. While coquinas present pore and throats of similar dimensions, dolomites have a significant amount of pores, mainly macropores, connected through restricting throats. The resistivity index curves for water/air saturations are typical, with a linear behavior, for both rocks. Coquinas kept a similar behavior when saturated with water and oil. However, dolomites tested with water/oil showed a double linear trend. The narrow throats seem to contribute to isolate water in the smaller pores at the lower range of water saturation.
Water Flooding Optimization for a Super-Giant Carbonate with Thief Zones
Authors: Wei Chenji , Li Yong , Li Baozhu , Wang Yinxi , cai Kaiping , Zhang Qi , Zhou Jiasheng 
Published: September 2015

Abstract
Understanding the heterogeneity is critical for a successful water injection in a carbonate reservoir. Thief zone is one of the most obvious forms of heterogeneity, which indicates the thin layer with higher permeability compared with average reservoir permeability. The existence of thief zone results in earlier water breakthrough and faster water cut increase, which lead to smaller sweep efficiency and lower recovery factor. Therefore, determining the thief zone distribution and proposing corresponding development plan are very important.
This paper focuses on a super-giant carbonate reservoir, which is a Cretaceous carbonate reservoir in Middle East, with an OOIP of more than 20 billion barrels. Thief zones are widely distributed in this carbonate according to the production logging test (PLT). In this paper, we combined geological understanding and dynamic behavior to summarize different types of thief zone distribution, which means the different locations and scales of thief zone and barriers. Then, geological model is built, and reservoir simulation is conducted on the models corresponding to different types to optimize the development strategy.
The optimized parameters include well pattern and perforation strategy. Then, development strategies are proposed for different types of thief zone distribution. Results indicate that location of thief zone hasobvious impact on the production. In order to mitigate the impact of thief zone, line drive pattern is preferred when the permeability ratio is high. Most importantly, different types of thief zone distribution require specified perforation strategy, and optimizeddevelopment strategies could save more than 25% of injected water by mitigating the futile cycle of injected water.
This paper offers a case study that summarizes different types of thief zone distribution and optimizes the development strategy for different scenarios. It also provides a methodology and reference case for engineers and geologists to develop other similar fields.
A Case Study: Modeling Challenges of Miscible Gas Injection (MGI) Project of Tight Sour Oil Field Developed with Hydraulically Fracced Wells
Authors: Cobanoglu M. , Mahruqi F. 
Published: September 2015

Abstract
The reservoir in South Oman – discovered in 1989 – is a 400m thick, tight, micro-porous silicilyte slab encased in salt at a depth of 4000m. The field contains the unique Athel silicilyte formation, some 4 km below the surface and is fully encased in salt as a result of which the reservoir is over-pressured at 800 bars.
The crestal area has average matrix porosity of 22% and the permeability of the reservoir is extremely low (typically 1 – 100 μD). The oil in this field is very light, sour, low viscosity and volatile (48° API, Pb=260 bar, H2S=1.5mol%, CO2=2.5mol%). The application of massive hydraulic fracturing (2-5 fracs/per well) combined with the favorable oil properties and undersaturated nature of the oil has made economic primary depletion development possible in this low permeability reservoir with initial oil rates in the range of 100-600 m3/day. Current oil recovery factor is 4.2% and expected to reach 10% through continued primary depletion.
MGI via hydraulically fractured wells is seen as possible EOR method to improve field recovery. A pilot injection phase consisting of 2 inverted 5-spot patterns in the crest of the reservoir will start Q2-2015 followed by a 2nd phase of crestal MGI by 2026. The purpose of the current dynamic modeling is to assess the 2nd phase of crestal MGI.
The modeling challenges are complex reservoir characteristics (vertical and areal heterogeneity), tight reservoir nature, hydraulically fracced wells, sour content and MGI. The subsurface complexity requires a detailed static model (areally and vertically) combined with preferably a compositional dynamic model. Obviously, run time of a compositional dynamic model is increasing dramatically with increasing complexity which is limiting the practical applications.
Several solutions to optimize the running time and accuracy have been investigated (i.e. explicit or implicit modeling of fracs, rate or THP control, black oil versus EOS models, various up-scaling options, sector versus full field models), tested and calibrated with historical data. In addition, history matching of more than 14 years production history of 43 wells with 25 fracs/well was another significant challenge. Different approaches, e.g. single/multiple case deterministic (MultiRun) and Design of Experiments (DoE) approach have been investigated for both history match and forecasting.
This paper covers a fit for purpose modeling approach, using Shell’s in-house simulation tool MORES, with powerful functionalities that enable modeling of the subsurface complexity in order to make the field development decision on the MGI extension. In addition, successful application of uncertainty modeling and assessment by using a classic approach (i.e. deterministic models) and a stochastic approach (i.e. DoE using assisted HM methods) will also be covered in the paper.