bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Review on Recent Advances in the Numerical Simulation for Coalbed Methane Recovery Process
Authors: Wei X. R. , Wang G. X. , Massarotto P. 
Published: December 2007

Abstract
The recent advances in numerical simulation for primary and enhanced coalbed methane (CBM/ECBM) recovery processes are reviewed, focusing primarily on the progress that have occurred since a similar review paper was published by King and Ertekin in 19891,2. Two major issues regarding the numerical modeling will be focused on in this review: firstly, multicomponent gas transport in in-situ bulk coal and secondly, changes of coal properties during methane production. For the former issues, a detailed review of more recent advances in modeling gas and water transport within coal matrix is presented. Further, various factors influcing gas diffusion through coal matrix will be highlighted as well, such as pore structure, concentration and pressure, and water effects. An ongoing bottleneck for evaluating total mass transport rate is developing a reasonable representation of multi-scale pore space that considers coal type and rank. Moreover, few efforts have been involved to model water flow behavior in coal matrix and its effects on both CH4 production and on the exchange of CO2 and CH4. As for second issue, theoretical coupled fluid flow and geomechanical models have been proposed to describe the evolution of pore structure during methane production, instead of traditional empirical equations. However, there is currently no effective coupled model for engineering applications. Future perspectives of developing suitable simulation models for CBM production and predicting CO2-sequestration ECBM recovery are suggested.
Accurate Modeling of Matrix-Fracture Transfers in Dual-Porosity Models: Optimal Subgridding of Matrix Blocks
Authors: Famy C. , Bourbiaux B. , Quintard M. 
Published: December 2007

Abstract
This paper proposes a sub-gridding technique to improve the reliability of matrix-fracture exchanges predicted by dual-porosity simulators. As a preliminary target, this sub-gridding technique was designed for the capillary imbibition case, by taking into account the physical specificities of this mechanism while minimizing the computational cost. Very accurate exchange terms are obtained, showing interesting perspectives of application of this modelling methodology.
Quantifying Petrophysical Uncertainties
Authors: Adams S. J. 
Published: December 2007

Abstract
Typical petrophysical deliverables for volumetric and modeling purposes are net reservoir, porosity, permeability, water saturation and contact locations. These data are usually provided without quantitative determination of their uncertainties.
Current computing power renders it now feasible to use Monte-Carlo simulation to determine the uncertainty in petrophysical deliverables. Unfortunately, quantitative uncertainty definition is more than just using Monte-Carlo simulation to vary the inputs in your interpretation model. The largest source of uncertainty may be the interpretation model itself.
This paper will use a variety of porosity interpretation models to illustrate how the impact of each input on the uncertainty varies with the combination of input values used in any given model. It will show that use of the incorrect model through oil and gas zones may give porosity estimates with Monte-Carlo derived uncertainty ranges that exclude the actual porosity.
Core data provides the best means of quantifying actual uncertainty in the petrophysical deliverables. Methodologies for deriving uncertainties quantitatively by comparison with core data will be presented. In the absence of core data, interpretation models should have been tested against core data through the same or similar formations nearby. Monte-Carlo simulation can then be used as an effective means of quantifying petrophysical uncertainty. Comparisons between the core comparison and Monte-Carlo techniques will be made, showing that similar results are achieved with the appropriate interpretation models.
The methodologies described in this paper are straightforward to implement and enable petrophysical deliverables to be treated appropriately in volumetric and modeling studies. In addition, quantification of petrophysical uncertainty assists in operational decision-making by letting users know how reliable the numbers produced actually are, and what range of properties is physically realistic. Such work also allows the key contributions to uncertainty to be defined and targeted if overall volumetric uncertainty must be reduced.
Development and Introduction of Heavy Organic Compound Deposition Diagnostics, Prevention and Removing
Authors: Voloshin Alexander I. , Ragulin Victor V. , Telin Alexey G. 
Published: December 2007

Abstract
One of the major unsolved complex systems confronting the petroleum industry at present is the untimely depositions present in oil.
Deposition of asphaltene, resin and paraffin at the formation bottom-hole zone refers to less controlled processes. The paper discusses a integratid approach to forecasting asphaltene, resin, paraffin precipitation in the formation bottom-hole zone, analysis of technological and economic efficiency of bottom-hole zone treatment using oil solvents carried out at the fields of Western Siberia and Volgo-Ural petroleum region.
The method to evaluate the tendency of formation oil to deposit asphaltene, resin and paraffin under the conditions of a sharp change in thermo-baric conditions in the formation bottom-hole zone has been developed on the basis of physical-and-chemical properties of surface oil, namely viscosity, density, quantitative content of asphaltene and resin, refractive index, thermal effects of asphaltene flocculation with the account of geological properties of the petroleum reservoir. Correlation dependencies of oil heavy component composition upon its properties have been found. Maps of a number of fields have been built taking into account the risk of asphaltene, resin, and paraffin deposition. The developed method is used as the basis for choosing candidate-wells for bottom-zone treatment.
To renew well productivity, it is considered optimal and efficient in the conditions of Western Siberia to carry out the bottom-hole zone treatment using hydrocarbon solvents. To date more than 1300 treatments have been carried out at 20 fields.
The theoretical foundation for solvent selection to remove asphaltene, resin, and paraffin deposits in oil wells, pumps, storage vessels, transfer pipelines has been developed on the basis of modern concepts of structure, properties and reactivity of asphaltene and resin, as well as analysis of thermodynamic and kinetic aspects of solvents interaction with petroleum disperse systems.
Risk and Uncertainty Modelling in the Oil and Gas Industry
Authors: Faisal F. , Al-Thani J. , Merna T. 
Published: December 2007

Abstract
The management of risk is one of the most important issues facing the oil and gas industry today. This paper will focus on the need for risk management in the oil and gas industry. A typical project from a major oil and gas producer has been selected and its typical risks identified. The risks are analysed and modelled in the CASPAR (Computer Aided Simulation for Project Appraisal and Review) program. The paper distinguishes between pure risk and spread risk for forecasting the economic parameters of different risk scenarios.
The increasing pace of change, customer demands and market globalisation all put risk management high on the agenda for forward thinking companies. It is necessary today to have a comprehensive risk management strategy. Having a process in place to identify, analyse and manage risks is paramount. The oil and gas industry is fraught with risk and it is necessary for these risks to be assessed continuously.
In this paper, the authors examine the downstream risks inherent in the oil and gas industry and differentiate between the more manageable/quantifiable pure risks such as construction, health and safety and project management and the less manageable spread risks associated with war, terrorism and market demand which affect the price of oil and gas.
Productivity Assessment of Fractured and Non-Fractured Wells in a Lean/Intermediate Low Permeability Gas Condensate Reservoir
Authors: Baig T. , Droegemueller U. , Gringarten A. C. 
Published: December 2007

AbstractThis paper compares the near-wellbore behaviors and productivities of a vertical non-fractured well and a vertical hydraulically fractured well in a low permeability, lean/intermediate gas condensate reservoir, when the flowing well bottomhole pressure falls below the dew point pressure. Under this condition, two phases, reservoir gas and liquid condensate, coexist near the wellbore and a condensate bank is formed, reducing the productivity of well.Productivity impairment is investigated with single well, fine grid, compositional simulations and analyzes of simulated pressure transient tests.Reservoir simulation and simulated pressure transient tests show that, in this low permeability reservoir, there is no evidence of capillary number effects, due to low sustainable production rates and high interfacial tension. Effect of production rate and time on well productivity is investigated.Fracturing the well before the formation of the condensate bank significantly improves productivity. Stimulation reduces the pressure drawdown, leading to less liquid condensate drop-out near the wellbore, thus delaying the formation of the condensate bank. The length of the fracture controls the productivity: a long fracture yields a higher productivity improvement, despite a lower dimensionless fracture conductivity, because the reduction in pressure drawdown far exceeds the pressure loss inside the finite conductivity fracture. Stimulation of the well after the formation of the condensate bank, with a fracture length extending beyond the bank, is also investigated.Challenges associated with the simulation of hydraulic fractures in gas condensate field studies are briefly discussed.
Scale Inhibitors Designed for Zinc Bromide High-Density Completion Brines
Authors: Wang X. , Ke M. , Qu Q. 
Published: December 2007

Abstract
Zinc bromide high-density brines are widely used in well completions, and zinc sulfide scale, which can cause formation damage and production decline, has been reported in some well completions. When severe scaling occurs, costly acid stimulation treatments are required to restore well production. Therefore, it is highly desirable to add an effective ZnS scale inhibitor directly to ZnBr2 brines before scaling can occur downhole.
While scale inhibition methods for sulfates and carbonates in production equipment and reservoirs have been extensively studied, only limited literature for sulfide scales exists. Of the limited case, most are related to treatment in production tubing and topside process facilities, i.e., low zinc concentration in produced waters. Unlike traditional scale inhibitors which are typically applied in fresh water or very low salt solutions (~3 % salt), inhibitors designed for zinc brines need to be compatible with more than 50% dissolved salt. In zinc brines, the extremely high salt content and the limited amount of free-water severely restrict both the solubility and effectiveness of inhibitor candidates. Furthermore, most wells using high-density zinc brine are high-temperature high-pressure, and conventional scale inhibitor evaluation methods are not adequate. New evaluation methods were developed to test scaling tendencies and inhibition under downhole conditions.
This research work was focused on the development and evaluation of ZnS scale inhibitors compatible with high-density zinc brines. Candidate chemicals were selected based on their potential ZnS scale-inhibition characteristics, and were studied in high-density zinc brines at high temperatures. Details of the test methods and results are presented for several ZnS scale inhibitors.
Multi-Rate Transfer Dual Porosity Modeling of Gravity Drainage and Imbibition
Authors: Donato Ginevra Di , Lu Huiyun , Tavassoli Zohreh , Blunt Martin J. 
Published: December 2007

Abstract
We develop a physically-motivated approach to modeling displacement processes in fractured reservoirs. To find matrix/fracture transfer functions in a dual porosity model we use analytical expressions for the average recovery as a function of time for gas gravity drainage and counter-current imbibition. For capillary-controlled displacement the recovery tends to its ultimate value with an approximately exponential decay.1 When gravity dominates the approach to ultimate recovery is slower and varies as a power-law with time.2 We apply transfer functions based on these expressions for core-scale recovery in field-scale simulation.
To account for heterogeneity in wettability, matrix permeability and fracture geometry within a single grid block we propose a multi-rate model.3 We allow the matrix to be composed of a series of separate domains in communication with different fracture sets with different rate constants in the transfer function.
We use this methodology to simulate recovery in a Chinese oil field to assess the efficiency of different injection processes. We use a streamline-based formulation that elegantly allows the transfer between fracture and matrix to be accommodated as source terms in the one-dimensional transport equations along streamlines that capture the flow in the fractures.4–6
Application of Streamline Method to Hot Waterflooding Simulation for Heavy-Oil Recovery
Authors: Pasarai U. , Arihara N. 
Published: December 2007

Abstract
We extended the streamline method to model hot water-flooding process in a heavy oil reservoir that underwent cold water-flooding. The pressure equation for defining streamlines was derived by summing up the mass conservation equations with compressibility and depletion taken into account. The mass and energy equations in terms of streamline time-of-flight coordinates were solved for each streamline by the Newton-Raphson's procedure based on an implicit single point upwind scheme. The thermodynamic calculations were performed along streamline to account for the changes in properties with temperature and pressure.
The developed simulator was tested for a hot water-flooding simulation in one-dimensional (1D) and two-dimensional (2D) heavy oil reservoirs and verified by comparison with a commercial thermal simulator. Tests showed the ability of the streamline method to simulate the hot water-flooding process with faster calculation speed.
An Alternative for Saving Gas Burnt in Well-Testing Operation by Using MPFM— A Case Study
Authors: Wijayanti H. 
Published: December 2007

Abstract
TOTAL E&P INDONESIE, one of Production Sharing Contractors in Indonesia, manages its field located in East Kalimantan, Indonesia. Under well servicing department, one of its activities in support and service operation is well testing. The scope of work consists of production test, offload, clean up, start up and support data acquisition.
There are some challenges faced in well testing activity, both in environment and operation point of view. In environment point of view, it happens frequently that the tested fluid cannot be routed back to the flow line or production network because of some reasons. Since the tested flow cannot be re-routed, it can only be released to the environment after formerly burnt. So, reducing the amount of gas burnt becomes one of the environmental challenges in well testing.
In operation point of view, the requirement of well testing is increasing from time to time. To fulfill the demand, more testing unit is required from time to time. The testing unit can be a testing barge or a MPFM, either a complete package of MPFM on a dedicated self-propelled barge, or just a portable MPFM unit mounted on other barge with other unit on it (e.g. portable MPFM mounted on slick line barge).
In Tunu – Tambora field, the average volume of annual flaring is approximately 1,900 mmscf. This amount is apportioned among gas burnt resulting from offload, clean up, start up, production test, MRPL, and BPT. Gas burnt from production test, MRPL, and BPT operation is potentially saved by using MPFM. Gas from offload (atmospheric pressure) is also possible to be re-routed to production network with the installation of multiphase pump at the return line.
Potential gas recovered through MPFM based on the percentage of gas burnt resulted from production test, MRPL and BPT is more or less 590 mmscf per year. With this value, approximately US$ 1.5 MM per year can be saved with the assumption that only 80% of the potential gas is recovered.
Knowledge Discovery in Drilling Optimization for Eliminating Surprises
Authors: Bi Xueliang , Yan Tie , Zhang Shurui , Wang Changjiang 
Published: December 2007

Abstract
Drilling process has a nature of surprise and uncertainty. It is urgent for us to decrease the drilling problems and to increase drilling speed. The scale of drilling data is becoming larger and larger. However there are plentiful and valuable knowledge hidden behind them. It is of great benefit to grasp the potential information. It will be beyond people's capacities when artificially analyzing and understanding these data stored in such a great database, so the techniques of knowledge discovery and data mining are arising at the historic moment. Knowledge discovery in drilling analysis, process monitoring and control is a new and important technology. Though still in its infant stage, it shows great application prospects. Its development, present application state and general process are briefly described in this paper. Then the authors analyze the approaches, the application and the theory of data mining and knowledge discovery for drilling analysis, process monitoring and control. Through analyses of characteristics of operational data, the authors also point out the challenges for data mining and knowledge discovery for process monitoring and control and contents to be studied. At last, the application of knowledge discovery in drilling optimization in Daqing Oilfield is analyzed.
Integrated Reservoir Assessment: A Way To Identify "Overlooked" Multilayered Reservoirs
Authors: Nikijuluw R. , Suwito Z. A. , Arianto M. A. 
Published: December 2007

Abstract
Semberah field is an oil and gas field that contains of complex multi-layer reservoirs of deltaic environment. As the field matures, the development strategy and approach have been focused on the smaller reservoirs (each &lt; 5 BCF IGIP), which were probably overlooked in early development stage. Therefore, detail integrated reservoir assessment (geological facies analysis and engineering wellbore evaluation) becomes very important.
The paper will demonstrate a successful case of such integrated assessment in the thinly Fxx sand series, which was overlooked. The initiative assessment was started when there are two thinly sands (9 feet - FxxC and 6 feet – FxxD) penetrated in one of the newly drilled wells, namely well-G. Based on detail geological facies analysis, this Fxx series can actually be divided into 6 different thinly sands, FxxA/B/C/D/E/F. A further production analysis shows that these two permeable FxxC and FxxD sands in well-G are believed to be different from the "water-out sands" in the two offset wells. The perforation was taken from FxxC and FxxD in well-G resulting rate gain 17 MMCF of dry Gas and no Water. Followed with another perforation in one of this series of FxxB in well-E, which is also believed to be different from the ones in well-G, resulted 11 MMCF of gas and no Water.
Managing Uncontrollable and Controllable Uncertainties Using EDA Methods: A Fluvial-Reservoir Case Study
Authors: Peng C. Y. , Gupta R. , Vijayan K. 
Published: December 2007

Abstract
A synthetic but realistic fluvial reservoir case study is used to study the performance of the experimental design and analysis (EDA) methods. A single 3-level fractional factorial design (81 design runs) is selected to capture the likely significant effects from 14 input variables. They consist of uncontrollable subsurface uncertainties (porosity, variograms, channel dimensions, endpoint saturations etc.) and controllable engineering uncertainties (number of wells). Expert opinion regarding the likely significant effects is used as the helpful information in selecting the design matrix. This single design matrix enables the comparison of three output response probability distribution curves generated from three different development scenarios.
A response surface equation model is developed to predict the P90, P50 and P10 values. Unless the equation model is fairly accurate, these predicted percentile values could be uncertain. The prediction error can be large if the design matrix does not pick up majority of the significant effects. To evaluate the developed equation model, cross-validation method and additional test runs are used. In this case study, the 81 run design enables the development of a reasonably good response surface for prediction purposes.
For decision making purposes, bootstrap confidence intervals can be used to quantify the uncertainty at the derived percentile values. Wide confidence intervals at the percentile values mean the predictions are less convincing. With these confidence intervals at the P90, P50 and P10 regions, possible 3D models at such percentile values can be selected, if desired.
A Novel Adaptive Anisotropic Grid Framework for Efficient Reservoir Simulation
Authors: Nilsson J. , Gerritsen M. , Younis R. 
Published: December 2007

Abstract
We present a novel parallel Adaptive Mesh Refinement (AMR) framework for the effective simulation of reservoir simulation processes. The framework is based on a Cartesian Cell-based Anisotropic Refinement (CCAR) strategy. The development was motivated by compositional and non-isothermal recovery methods, in particular miscible gas injection and in-situ combustion, and particularly suited to these applications. CCAR offers aggressive grid adaptation, which allows quick transition to the very fine local grids necessary to resolve solution fronts and the fine local grids desirable to resolve reservoir heterogeneity. CCAR is computationally efficient because of the underlying Cartesian topology, and requires minimal user intervention in the grid generation process. We use static refinement to generate a fixed base CCAR grid that accurately resolves the flow field, and propose a multi-level local-global upscaling strategy to determine appropriate permeability values for the CCAR grid. Dynamic refinement criteria are formulated to add adaptivity to the base grid where desired for accurate computation of transport. We also present a novel higher order pressure solver on the CCAR grids. The discretization uses a compact stencil, which together with an effective storage scheme leads to computational efficiency. The equations are solved with a parallel Algebraic Multigrid code.