bluuebunny/crossref_metadata_2025 huggingface dataset:
Corrosion and Selection of Alloys for Carbon Capture and Storage (CCS) Systems: Current Challenges
Authors: Chambers B.. , Kane R.. , Yunovich M..
Published: February 2011

Corrosion by CO2 causes significant metal loss when compared with equivalent pH acid system, because, unlike proton reduction in conventional acid-based corrosion, there is a concomitant reaction here, stemming from direct reduction of un-dissociated carbonic acid. Given that carbonic acid is weakly ionizing acid, oxidizing and corroding potential of acidic CO2 system is significant.

Experience shows that if the liquid water quantity in stream is limited and the system consistently operates above the dew point, high CO2 partial pressures can be handled in carbon steel equipment. However, when water condensation occurs, corrosion rates of steel due to carbon dioxide corrosion can be in range of 10 to 20 mm/yr. Therefore, appropriate phase behavior modeling, including ionic descriptions of different, relevant components and system speciation is an important aspect of this and any corrosion study.

In the present case of CCS, the stream can also contain "trace" compounds such as SO2, NOx and Hg that arise from fossil fuels and their combustion. Interactions between the species involved in "normal" carbon dioxide corrosion and these stream constituents pose an extreme risk of corrosion to steel and possibly certain corrosion resistant alloy (e.g.13Cr through alloy 825) equipment and which is not predicted by commonly used corrosion prediction methodologies.

Oil and gas industry has accumulated substantial experience and material technology to mitigate CO2 corrosion, which includes substantial laboratory data collected at high temperature and pressure conditions in service environments. In addition, corrosion models have been developed for assessment of service environments, phase behavior and effects of impurities, along with corrosion prediction and alloy selection that are widely used in the petroleum industry.

The paper addresses the following aspects of corrosion-related challenges to CCS equipment and systems, specifically focusing on the metallic materials employed for the service:Predominant corrosion/cracking mechanisms and other materials issues resulting from implementation of CCS processes.Relevant and current practices and experience relative to corrosion control and materials selection and the impact of variations in process conditions.Materials and corrosion research gaps analysis for optimizing materials performance of CCS systems.
The Significance of Caprock Sealing Integrity for CO2 Storage
Authors: Busch A.. , Amann A.. , Bertier P.. , Waschbusch M.. , Krooss B. M.
Published: February 2011

The safe long-term storage of gas/CO2 in spatially limited underground volumes requires the combination of a structural trap with intact structural integrity and a suitable low permeability caprock (seal). The occurrence of natural gas reservoirs proves that certain lithotypes do provide efficient seals which can prevent leakage of gas to the atmosphere over long geological time periods (millions of years). In order to assess the risk of CO2 leakage through caprocks on top of potential storage sites to the surface one has to consider both, the present sealing capacity of the rock and its likelihood to alter in contact with CO2.

The aim of this paper is to provide an overview of mechanisms affecting sealing integrity of intact (non-fractured/faulted) caprocks. Although certain caprocks can be suitable for hydrocarbons over geological time periods, CO2 in contact with the seal may pose additional risks. Depending on the lithofacies and the amount of reactive mineral species, CO2/water/rock interactions might alter the caprock, physical adsorption on organic matter or mineral surfaces will affect sealing integrity and interfacial properties will affect capillary entry and fluid transport behaviour.
Multiphase Analysis for CO2: Water/Mixed-Gas Adsorption on Coals
Authors: Mohammad S. A. , Robinson R. L. , Gasem K. A.
Published: February 2011

Traditional modeling of gas adsorption on wet coals does not include water as a separate adsorbed component; instead, the adsorbed water is viewed as a "pacifier" of the coal matrix. In this work, we modeled gas adsorption on wet coals by considering water as an active component in a binary mixture. Specifically, we used the simplified local-density/Peng-Robinson (SLD-PR) model to investigate the effect of the water present in coals on gas adsorption under the conditions encountered in coalbed methane (CBM) and CO2 sequestration applications. To conduct this study, our previously acquired measurements for high-pressure CO2 adsorption on wet coals were utilized.

When water is treated as one of the adsorbed components in a high-pressure gas adsorption system, as many as three phases may coexist at equilibrium. To investigate the phase behavior of CO2/water adsorbed gas mixtures on wet coals, a new algorithm was developed to facilitate a Gibbs energy-driven multiphase analysis of this system. The algorithm uses a phase-insertion technique, which involves formally inserting a third (liquid) phase and solving a three-phase flash problem, wherein the three phases are the adsorbed, bulk gas and liquid phases. At equilibrium, the total Gibbs energy of the system is calculated based on the phase distribution obtained at each step. This calculation is repeated sequentially with incrementally increased amounts of the inserted third phase. A Gibbs energy analysis for CO2/water mixed gas adsorption on wet coals was conducted utilizing this new algorithm.

Results involving CO2/water mixtures on four well-characterized coals indicate that the SLD-PR model is capable of representing the adsorption of these highly asymmetric mixtures within the experimental uncertainties. The Gibbs analysis of these coals indicates that there is a third phase present in systems that contain large amounts of moisture. The third, water-rich phase appeared typically at the higher pressures in the isotherm.
Lenses Heterogeneity Effects on Water Alternating Gas Injection in Oil Wet Porous Media
Authors: Al-Wahaibi Yahya. M. , Al-Hadrami Abdullah. K.
Published: February 2011

This paper reports the results of extensive experimental and numerical studies of the effects of well-defined heterogeneous oil-wet porous media (lenses) on simultaneous first contact miscible water alternating gas (FCMWAG) displacements. Flow displacement and effluent profiles have been obtained from well-characterized laboratory experiments in two-dimensional heterogeneous beadpacks. The effects of WAG ratios have been examined. All experiments were then modeled using IMPES finite difference simulator without using history matching (all simulations used directly measured porous media properties as inputs) to quantify the accuracy of the simulation when modeling the FCMWAG displacements in a porous media with lenses heterogeneity. Results revealed that neglecting lenses heterogeneity will cause incorrect reservoir engineering interpretation; for example that of core floods for absolute permeability, relative permeability and residual oil saturation determinations.
Capture and Sequestration of CO2 Produced by In-Situ Combustion Pilot Project, Orinoco Oil Belt, Venezuela: A Mineral Carbonation Laboratory Assessment
Authors: Perez M.. , Barrios M.. , Vasquez P.. , Losada R.. , Salcedo M.. , Perozo H.. , Ortega P.. , Diaz M..
Published: February 2011

The In Situ Combustion Pilot Project (ISCPP) is an ongoing testing effort aimed at assessing the efficacy of this thermal process to increasing recovery factor in the exploitation of heavy oil reservoirs from Orinoco Oil Belt (Venezuela). The process is expected to produce 3 to 7 million cubic feet/d of combustion gases, with an anticipated composition of 20% CO2(g) and 80% N2(g). As an option for Carbon Capture and Storage of produced CO2, mineral carbonation in caustic byproducts (liquor and red mud) from alumina production was assessed at lab scale. Byproducts were characterized showing pH values 12 - 14 and important quantities of NaOH. Caustic liquor and red mud were exposed to gas blends (ambient pressure and temperature) with 10 and 20% CO2(g) in N2(g), as well as pure CO2(g), until reaching pressure stabilization into liquid-gas system. Red mud suspensions with various densities were exposed as well to gas blends during several cycles. Saturation point was reached when consumption of NaOH was completed, resulting in the precipitation of Na2CO3. Results showed that caustic mud has a CO2 capture capacity of 7.9 kg CO2(g)/m3, or 19 kg Na2CO3/m3 reaching pH 8.3 at carbonate equilibrium. On the other hand CO2 capture capacity of the red mud was 87 kg CO2(g)/m3. Thermogravimetric analysis of red mud (270 - 670 °C) shows less than 2% mass loss which is a good indicator of actual CO2 sequestration. ISCPP will produce around 77000 ton CO2(g) in 3 years of operation, and caustic liquor from alumina process will have sufficient capacity for its complete capture. Results revealed the existence of an important sink for CO2(g) to be produced in Orinoco Oil Belt, which would diminish as well the hazard of caustic liquor and red mud.
Use of a Mechanistic Model To Forecast Cement-Sheath Integrity for CO2 Storage
Authors: Bois A-P.. , Garnier A.. , Galdiolo G.. , Laudet J-B..
Published: February 2011

Implementation of CO2 storage in geological media requires a proper assessment of the risk of CO2 leakage from the storage sites. In particular, it is necessary to evaluate the risk that cement sheaths represent leakage pathways as this could occur if cement becomes damaged or when debonding exists at one of the interfaces of the cement sheaths.

Tests performed in the laboratory have shown that there exist two types of mechanisms that could lead to cement-sheath loss of integrity: mechanical degradation, when cement is submitted to compressive or tensile loadings that are too high, or chemical degradation. The worst case is when both mechanisms occur at the same time or one after the other. For example, a cement sheath that is damaged before entering in contact with a degraded fluid will allow this fluid to penetrate deeper in the cement sheath, hence accelerating cement chemical-degradation.

Hence, it is of paramount importance to understand the mechanisms that could lead to a cement-sheath loss of integrity before CO2 storage. This is with this objective, that we have been working on a mechanistic model that accounts for the various modes of cement-sheath loss of integrity after cement has been placed: a) cement volume-variations during hydration due to chemical shrinkage/expansion; b) cement volume-variations during hydration due to cement heat-production; c) contraction (dilation) of the casing due to a decrease (an increase) in mud density/temperature; d) cement volume-decrease due to pore collapse; e) thermal cycling.

This paper has two objectives: presenting the mechanistic model and using this model to show that cement sheath loss of integrity not only depends on cement properties but also on the well architecture and well history.
Use of CO2 in Heavy-Oil Waterflooding
Authors: Nasehi M.. , Asghari K..
Published: February 2011

Waterflooding has been used in oil recovery for many years and is an important technique in conventional oil recovery. In the case of viscous heavy oils, due to the low mobility of heavy oil and high mobility ratio between the displacing fluid (water) and the displaced fluid (heavy oil), reported recoveries have been very low and have been associated with very high volumes of produced water.

Use of CO2 in heavy oil waterflooding, as a solvent that might effectively reduce the viscosity of heavy oil and causes it to swell, is the focus of this study.

This paper presents the results of eleven core-flooding experiments designed to study the effect of CO2 utilization in waterflooding of heavy oils. Injection strategies used in these experiments involved different combinations of CO2 and brine, including intermittent injection of separate slugs as well as injecting carbonated water. In reported experiments, following the completion of waterflooding tests, CO2 slugs of 10% and 25% pore volumes, or carbonated water was injected into the cores followed by a shut-in period. Water injection was resumed at the end of shut-in period, and any additional oil produced was collected. Heavy oil samples with viscosities of 1000 to 2000 cp were used and experiments were carried out at pressures of 500 and 1000 psi (3.45 and 6.9 MPa), temperature of 30°C, and water injection rates between 1 and 50 feet per day. Carbonated water used in these experiments was prepared by dissolving CO2 in brine (1% wt. NaCl) at 820 psi over 4 days.

Results of this study indicate that the use of CO2 significantly improves recovery of heavy oil by waterflooding. Incremental recoveries in the range of 5 to 27.5% OOIP were achieved by CO2 in combination with waterflooding. It was also found that the increase in the operating pressure results in increased oil recovery. Furthermore, the injection of larger CO2 volume increased the oil recovery. It was also found that during the post CO2 waterflooding, greater recovery improvements are achieved from lower permeability systems. Comparison between the lower and the higher viscosity oils also showed that the use of CO2 results in greater recovery improvements for the higher viscosity oil system.
Numerical Simulation and Modeling of Enhanced Gas Recovery and CO2 Sequestration in Shale Gas Reservoirs: A Feasibility Study
Authors: Kalantari-Dahaghi A..
Published: February 2011

The process of modeling ultra low permeability and desorption-controlled shale gas reservoirs has always been challenging. Desorption is an important issue in recovery of many shale plays. Although a large amount of gas in place comes from adsorbed gas, ultra tight matrix and high bottom hole pressure may not allow this gas be produced.

In this paper, an integrated workflow is described, which demonstrates a quantitative platform for shale gas production optimization through capturing the essential characteristics of shale gas reservoirs. Because organic matter has a greater sorption affinity for CO2 than methane, a comprehensive feasibility study has been performed to evaluate the applicability and significance of CO2 injection (with simultaneous production of methane) on expedition of desorption process and also CO2 sequestration in shale.

Modeling of complex fracture networks is a very important step in simulation of shale reservoirs. Discrete fracture network (DFN) models can be used to generate and validate multiple realizations for a quantitative measure of uncertainty. A 3-D discrete fracture network using typical shale properties was generated stochastically, based on different realizations (homogenous and heterogeneous fracture properties). The complex DFNs were upscaled in order to simulate fluid flow through the system. In addition, hydraulic fractures were introduced to the model. Sensitivity analysis has been performed on key matrix and fracture properties for both natural and hydraulic fractures.

Numerical simulation was performed using appropriate gridding (logarithmic local grid refinement around the hydraulic fractures) and, in order to capture long transient gas flow from matrix to fracture, multi porosity model with matrix sub grids has been employed. This step was followed by a history matching process and the fracture and reservoir properties were varied within a range that appears consistent with actual typical shale gas well performance. One model, which gave a better approximation of the actual production profile, was selected for CO2 injection study.

In order to understand the economic effect of matrix swelling on permeability and injectivity in the presence of CO2, different injection strategies (patterns, injection time interval and rate) were defined in order to recommend the best scenario for maximum and economic recovery.
Predicting the Migration of CO2 Plume Using Injection Data and a Distance-Metric Approach to Reservoir-Model Selection
Authors: Bhowmik S.. , Srinivasan S.. , Bryant S. L.
Published: February 2011

During the operation of a geological carbon storage project, verifying that the CO2 plume remains within the permitted zone will be of particular interest both to regulators and to operators. We demonstrate a model selection algorithm that refines an initial suite of subsurface models representing the prior uncertainty to create a posterior set of subsurface models that reflect injection performance consistent with that observed. Such posterior models can be used to represent uncertainty in the future migration of the CO2 plume. Because only injection data is required, the method provides a very inexpensive method to map the migration of the plume and the associated uncertainty in migration paths. We illustrate the method using a field data set.
Impurities in CO2 - Rich Mixtures Impact CO2 Pipeline Design: Implications for Calculating CO2 Transport Capacity
Authors: Jung W.. , Nicot J. -P.
Published: February 2011

Existing carbon dioxide (CO2) pipelines commonly contain over 90% of CO2 mixed with major impurities such as methane (CH4), hydrogen sulfide (H2S), and nitrogen (N2). Other minor impurities are carbon monoxide (CO), oxygen (O2), C2+ hydrocarbons, and H2O. CO2 is transported in the gas phase, liquid phase, or as a supercritical fluid. Phase behaviors of CO2 mixtures are based on the Vapor Liquid Equilibrium (VLE) and critical points of mixtures. The predictions of VLE are essential to the design and operation of CO2 mixture pipelines. The VLE and critical points for binary or ternary CO2 mixtures are predicted by Equations of State (EOS). This study illustrates how major impurities impact transport capacities of CO2-rich mixture pipelines. The calculations indicate that the flow capacity in the liquid phase is approximately twice as high as in the gas phase.
Perspectives on CCS Cost and Economics
Authors: Kheshgi H. S. , Bhore N. A. , Hirsch R. B. , Parker M. E. , Teletzke G. F. , Thomann H..
Published: February 2011

Focus on Carbon Capture and Storage (CCS) has grown over the past decade with recognition of CCS’s potential to make deep CO2 emission reductions and that fossil fuels will continue to be needed to supply much of the world's energy demands for decades to come. How CCS will compare to other options in the future depends critically on the cost of CCS (the focus of this paper) and resolution of barriers to CCS deployment, as well as costs and barriers for other emission reduction options.

This paper provides a comparison of the cost of electricity of five power generation options – coal and gas Combined Cycle Gas Turbine (CCGT,) with and without CCS and nuclear – and shows regions of carbon price and fuel prices where each can be economically viable.

Current cost estimates for coal CCS for Nth-of-a-kind power generation plant are in the 60-100 $/ton of CO2 avoided – higher than some of the earlier CCS estimates, and higher than the generally accepted range of expected carbon prices in the next two decades. The high cost of coal CCS suggests that:Gas based power generation is much more economical than coal CCS at carbon prices below 60-100 $/ton CO2.Even after carbon prices reach 60-100 $/ton CO2, gas CCS produces lower cost electricity than coal CCS as long as natural gas prices remain below 9 $/MBTU.Nuclear has a lower cost of electricity than coal CCS.

Although Coal or Gas CCS is unlikely to be economical in power generation over the next two decades, subsidized demonstrations of CCS are likely to occur. In addition, components of CCS technologies will continue to be economically practiced in early use segments such as natural gas processing and Enhanced Oil Recovery (EOR) operations. In this paper, we share ExxonMobil’s experience at LaBarge in using CO2 from a natural gas facility for EOR use – the single largest CO2 capture site for sub-surface injection in the world today. In the natural gas processing industry, CO2 separation cost is a fraction of the cost of CO2 capture in power generation due to its higher gas pressure, and the CO2 separation is typically necessary to monetize the natural gas resource.

In contrast, CCS for most refinery and industrial emissions is expected to be significantly more costly than power generation because the CO2 streams are typically smaller scale and more distributed than those from large power plants.

Realistic estimates of cost for CCS, as well as for other greenhouse gas (GHG) mitigation options, are an important input for focusing research, development and demonstration (RD&D) addressing barriers to applications that show the greatest promise, and development of sound policy.
Storing CO2 With Next Generation CO2-EOR Technology
Authors: Ferguson R. C. , Kuuskraa V. A. , Van Leeuwen T. S. , Remson D..
Published: February 2011

CO2 enhanced oil recovery (CO2-EOR) offers the potential for storing significant volumes of carbon dioxide emissions while increasing domestic oil production. This paper, based on a recently updated report for DOE/NETL, examines the effect that "Next Generation" technologies will have on the CO2 storage and oil production potential of CO2-EOR. The paper examines the causes of sub-optimal CO2 storage and oil recovery efficiencies by current CO2-EOR practices and how a group of advanced or "Next-Generation" CO2-EOR technology could increase both CO2 storage volumes and oil recovery. Technologies investigated include: using increased volumes of injected and permanently sequestered CO2, optimizing well placement and pattern alignment, and using reservoir miscibility and viscosity enhancers.
Influence of Thermo-Elastic Stress on CO2 Injection Induced Fractures During Storage
Authors: Luo Zhiyuan , Bryant Steven L.
Published: February 2011

Commercial CO2 geologic storage will require large injection rates and will favor pipeline transport of CO2 as a dense (liquid) phase. Thus the temperature of CO2 entering a storage formation may be significantly lower than the formation temperature. This difference in temperature introduces a thermo-elastic stress that reduces the critical pressure required for initiation of fractures. The initiation of fractures poses a potentially serious risk for CO2 leakage to upper formations or surface.

We present a simple model to predict the range of bottomhole fluid temperatures, and thus the range of thermo-elastic stresses, for different operating conditions. The operators and regulators can estimate the safe injection rate range based on the model to avoid injection-induced fracture initiation around an injection well. Different injection strategies are considered in this work. The effect of Joule-Thomson cooling across the perforations is investigated and found to be small. We also evaluate the sensitivity of safe injection rate to formation permeability, heat transfer coefficient, geothermal gradient, and surface temperatures of injection fluid and well. Results from this study provide a guide for risk assessment and form a basis for investigating the extension of initiated fractures.
Specialties of Energy Conservation and Application of Control Systems in a Large Cooling Water Project
Authors: Relwani Harendra , Sarma Anupindi , Salamat Reza
Published: February 2011

Having a battery of parallel operating pumps with variable speed drive system (VSDS) saves a great deal of energy especially for big pumps with large throughputs. Back in 80s and even 90s, however, relying on variable speed drive pumps with high target reliability and 100% availability was a big task mainly due to the complexities of the associated power electronics and the control issues. In the present era, sophisticated control equipment and philosophy allows taking the full advantage of VSDS pumping system whereby the pump generates a dynamic head only as much as plant requires. As a result the operator ends up in saving substantial operating expenditure in terms of energy bills and simultaneously reduces the environmental impact due to reduction in CO2 emission associated with the power generation. The larger the plants, the larger the consequent savings thus demanding due design attention at early stages.

The proceeding paper discusses the salient design and operational aspects of a large cooling sea water project in Ras Laffan, one of the largest industrial sites in the world, situated 80 km North of Doha in the state of Qatar. This project is unique in terms of its seawater throughput of nearly 1 Million m3/hr by variable speed drive pumps, through a set of very large diameter GRP pipelines to various end users spread throughout the industrial city, with varying seawater demand. These series of 27 pumps each around 7.5 MW with a future provision of additional 6 pumps are located in three separate pump houses. The project also boasts one of the largest electro chlorination plants in the world. The paper describes in sufficient detail the energy saving aspects of a large VSDS driven cooling water system and the associated reliable control with no allowable downtime that will jeopardize the water supply to any end user at any point of time. The design target reliability and availability are 99.7% and 100% respectively. The potential opportunities of pump head savings are identified and the associated benefits in power and CO2 emission are evaluated by comparing the various operational scenarios. The paper also describes the specialties and application of the control systems.

In the proceeding work it is found that on the current project alone, more than 400 GWhr of energy per annum can be saved by the application of VSDS system translating into a reduction in emission of nearly 170,000 tones of CO2 on annual basis. An efficient and robust control strategy has resulted in less operating costs in terms of energy bills and retarding the pollution of the environment.

With the use of cooling water plants around the world inevitably on the rise as more oil & gas facilities of mega size are being built, it is concluded that all viable power saving options should be explored at the early concept stages. Sufficient emphasis should be placed on energy optimization and the resultant environmental benefits.
Reservoir Modeling to Characterize Dual Porosity, Tengiz Field, Republic Of Kazakhstan
Authors: Tankersley T.. , Narr W.. , King G.. , Camerlo R.. , Zhumagulova A.. , Skalinski M.. , Pan Y..
Published: February 2011

Tengiz Field is the world's deepest developed supergiant oil field, with an oil column of nearly 1600m. The reservoir consists of Devonian and Carboniferous platform/slope carbonates, divided into three stratigraphically-defined units. Production of over 500,000 BOPD is mainly from the upper unit. A significant portion of this production is controlled by natural fractures. A new reservoir model has been constructed to support a future growth project, including miscible gas injection, and to guide reservoir management strategies, development planning, and oil-in-place estimation.

Our new model represents a significant change from previous models in that a dual porosity, dual permeability flow formulation (fracture and matrix) is being applied. This change to dual porosity, which is necessary to effectively characterize the fracture-matrix flow, requires a significant modification of the overall reservoir modeling workflow. Matrix porosity and permeability are distributed into the fine-scale model and fracture properties are populated into the model after upscaling, because representative fracture attributes are only available at a large scale.

Fracture porosity is high in the depositional slope (about 0.4%) due to the cavernous character of portions of the fracture system. This fracture porosity represents a significant volume, and has a large impact on reserves. Fracture permeability is also a critical factor, and has a large affect on flow behavior and recovery. Although fractures are important, their intersection by wellbores is relatively rare, due mainly to under-sampling of sub-vertical fractures by vertical wells and sparse well control in the slope. Because of this under-sampling, and general ambiguity in image-log data, uncertainty associated with fracture properties is large. To address this uncertainty, significant effort has gone into collecting reservoir surveillance data. In addition, fracture properties from image logs were reconciled with well tests and other logs.
Tengiz Field (Republic of Kazakhstan) Unit 1 Platform Static Model: Using a Hybrid Depositional – Diagenetic Approach
Authors: Kenter Jeroen A. , Tankersley Terrell , Skalinski Mark , Harris Paul (Mitch) , Levy Marge , Dickson Tony , Jacob Gary
Published: February 2011

Traditional rock typing combined with an inferred depositional linkage for variogram-based simulation is a standard approach in carbonates. In the Tengiz Unit 1 platform, reservoir properties of carbonates as defined by Petrophysical Rock Types (PRTs) are the product of primary depositional facies and diagenetic modification that have separate spatial trends and interactions. Careful, multidisciplinary and targeted analysis is required to unravel such trends from the usually complex hard data sets, but is critical as an understanding of the trends forms the basis for reservoir modeling of the Tengiz Unit 1 platform. Depositional cycles in the Unit 1 Tengiz platform (Late Visean to Bashkirian) are made up of a succession of generally shoaling lithofacies overlying a sharp base with evidence for subaerial exposure and/or flooding. Systematic study of the diagenetic products of several sequences across the platform using petrography, stable isotopes and CL revealed that the diagenetic modification includes early meteoric dissolution and subsequent cementation, late burial dissolution and late burial bitumen cementation. PRTs are designed to include spatial attributes of the combined stratigraphic, facies and diagenetic framework form the basis for the Multiple Point Statistics and Facies Distribution Modeling (MPS/FDM) simulation of the SIM08T Unit 1 static platform reservoir model. Of the six PRTs, one is linked to volcanic ash (PRT 1), one associated with bitumen (PRT 2) and four with increasing porosity (PRTs 3-6) where PRT 3 tight and PRTs 4-6 represent increasing reservoir quality with PRT 6 the highest quality. PRT maps and a vertical proportion curve were used to generate the facies probability cube and convolved with training images, specifying the spatial interrelationship, to generate a PRT realization. The revised sequence stratigraphic framework and integration of novel concepts in modeling the diagenetic overprint addressed the need for a refined understanding of the platform in preparation for the FGP miscible gas injection project. In addition, the extensive use of MPS/FDM modeling approaches in Unit 1 has resulted in a more realistic integration of both depositional and diagenetic trends in the Unit 1 platform.
Updated Rock Type Definition and Pore Type Classification of a Carbonate Buildup, Tengiz Field, Republic of Kazakhstan
Authors: Skalinski Mark , Kenter Jeroen , Jenkins Steve , Tankersley Terrell
Published: February 2011

Tengiz is an isolated Paleozoic carbonate build-up located in the Pricaspian Basin, Republic of Kazakhstan. The reservoir contains over 26 Billion Barrels OOIP and is one of the world’s deepest supergiant fields. The introduction of petrophysical rock types (PRT) and pore type classification has significantly improved oil in place estimation and reservoir characterization of this complex carbonate field.

The Tengiz platform is a cyclic alternation of grainstone and packstone with thin volcanic ash layers and later strongly modified by diagenesis. The Tengiz flank areas are dominated by microbial boundstone deposition in an upper slope environment and detrital sediment in the lower slope. Carbonate facies in the Tengiz flanks are generally tight with bitumen cement and are dissected by fracture systems which act as fluid conduits. The classification of pore types and development of algorithms to predict pore types are based on a data set of more than 550 mercury injection pressure measurements. The Tengiz pore classification is scale-driven and has a direct impact on permeability and flow performance. The character and distribution of pore geometries in Tengiz buildup is determined by a variety of depositional and diagenetic processes, including early differential cementation, mechanical compaction and failure, and phases of dissolution and calcite and bitumen cementation.

PRTs were developed to characterize various depositional and diagenetic regions of the Tengiz Field. Several distinct groupings of petrophysical rock types are recognized in the Tengiz platform and flank. These groupings include Volcanic Dominated, Bitumen Rich, Tight/Cemented, and reservoir facies of varying quality.

A set of SRT (Slope Rock Types) were developed to improve characterization of the Tengiz slope facies. The slope largely consists of tight, algal boundstone and breccia facies which have undergone extensive corrosive diagenesis. Permeability is significantly enhanced in the Tengiz slope through these diagenetic processes.

In 2008, a new reservoir model was constructed for Tengiz which implements the concepts of PRT and SRT to improve characterization of pore sizes and pore throats across the field. These distributions of pore size and pore throat geometry are a primary control on oil recovery in carbonate reservoirs. Improved characterization of pore geometry and key reservoir properties in the Tengiz Field has been achieved using petrophysical rock types. The introduction of PRT and SRT at Tengiz has contributed to improved estimates of volumes of oil in place and improved reservoir management.
Analogues as a Tool for Modeling Fields
Authors: Lapointe P. A. , Glass L. W.
Published: February 2011

Carbonate mounds are reported throughout the stratigraphic scale from the Proterozoic to the Present. They developed on continental margins or intra-platform environments, in water depths ranging 1000 to 10 m and represent targets for hydrocarbon exploration in Kazakhstan, leading to recent discoveries of giant hydrocarbon accumulations (e.g. Karachaganak, Grigor’yeva, 1992; O’Hearn et al, 2003). They generated renewed interest in these distinctive carbonate deposits. An understanding of recent carbonate mounds systems in particular those drilled by leg IODP 307, provides a tool to appraise ancient subsurface mound carbonates and as a complement classic outcrops studies.

The cyclic records observed in recent mounds are keys for understanding the reservoir compartmentalization within mound complexes. The comparative analysis of mound evolution – focusing on early to late diagenetic processes, products and patterns – in the recent and ancient deposits provides new insights into reservoir porosity and permeability.
A Multiscale Method for Modeling Flow in Stratigraphically Complex Reservoirs
Authors: Alpak Faruk O. , Pal Mayur , Lie Knut-Andreas
Published: February 2011

A robust and efficient simulation technique is developed based on the extension of the mimetic finite volume method to multiscale hierarchical hexahedral (corner-point) grids via use of the multiscale mixed finite element method. The implementation of the mimetic subgrid discretization method is compact and generic for a large class of grids, and thereby, suitable for discretizations of reservoir models with complex geologic architecture. Flow equations are solved on a coarse grid where basis functions with subgrid resolution accurately account for subscale variations from an underlying fine-scale geomodel. The method relies on the construction of approximate velocity spaces that are adaptive to the local properties of the differential operator. A variant of the method for computing velocity basis functions is developed that utilizes an adaptive local-global algorithm to compute multiscale velocity basis functions by capturing the principal characteristics of global flow. Both local and local-global methods generate subgrid-scale velocity fields that reproduce the impact of fine-scale stratigraphic architecture. By using multiscale basis functions to discretize the flow equations on a coarse grid, one can retain the efficiency of an upscaling method, while at the same time produce detailed and conservative velocity fields on the underlying fine grid.

The accuracy and efficacy of the multiscale method is compared to that of fine-scale models and of coarse-scale models with no subgrid treatment for several two-phase flow scenarios. Numerical experiments involving two-phase incompressible flow and transport phenomena are carried out on high-resolution corner-point grids that explicitly represent example stratigraphic architectures found in real-life shallow marine and turbidite reservoirs. The multiscale method is several times faster than the direct solution of the fine-scale problem and yields more accurate solutions than coarse-scale modeling techniques that resort to explicit effective properties. The accuracy of the multiscale simulation method with adaptive local-global velocity basis functions are compared to that of the local velocity basis functions. The multiscale simulation results are consistently more accurate when the local-global method is employed for computing the velocity basis functions.
Effect of Sand Production on Pressure Drop for Vertical Wells in Gas Storage Reservoir
Authors: Olufemi Adekomaya , Darlington Etaje
Published: February 2011

Sand production is a natural consequence of fluid flow into a wellbore from the reservoir. Sand production was found to be not a problem in the early part of the fields with high reservoir pressures. But the effect of sand transport on pressure drop becomes more pronounced in the late life of reservoir. Accurate estimation of pressure drop due to sand production has been of great interest for a long time for production engineers.

Numerous solutions to halt sand effect on flowing pressure in gas wells have been attempted with low degree of success. In this paper, a model was developed that analyzed the significant effect of sand on pressure drop during early and late life of a well which was not accurately predicted in existing models.
Three Phase Modelling of Production Log Data Leads to More Accurate Decision Making and Saves Cost
Authors: Ojonah Oke , Gysen Alain
Published: February 2011

In well and reservoir management, optimum and accurate determination of multiple phase well-bore fluid entry is required to make decisions on water/gas shutoff opportunities. This can only be possible if good quality production log data is acquired and most importantly if accurate data analysis is done.

This paper examines the drawbacks experienced using the conventional production log analysis methods and its associated risks. It will introduce an alternative probabilistic approach leading to more accurate results. The results of a case study will also be presented where a cement water shutoff was planned and executed based on the result of conventional analysis. It will also show how the results of the probabilistic approach would have saved the cost of the cement water shutoff
Using Experimental Design Table with Reservoir Simulation to Manage Subsurface Uncertainties - A Niger Delta Case Study
Authors: Cyril Ogbalor , Peacock Anthony
Published: February 2011

Experimental Design (ED) methods are becoming a well-established alternative to traditional uncertainty analysis due to the fact that it offers a more efficient and consistent approach to identify and assess the impact of the key subsurface uncertainties on field development decision. This paper describes a case study of applying ED to assess development risks in a gas reservoir in the Niger Delta. The reservoir is areally very extensive but relatively thin and underlain by aquifer. Key development and recovery risks were recognised to be access to pressure support and water breakthrough at the production wells. The objective of the study was to define realistic P10-P50-P90 subsurface realisations and test various development concepts against this range of models to generate an optimal field development strategy.

A multi step ED approach was used to understand and manage the key subsurface uncertainties. Alternative linear screening designs and multi-level response surface designs were used in this study.

Key outcomes of the study were:

– Successful demonstration of the application of Experimental Design technology and alternative screening designs – Generation of Response Surface models for In-Place and recoverable volumes. – Definition of a realistic range of sub-surface realisations for the reservoir and identification of P10-P50-P90 sub-surface models using Probabilistic (Monte-Carlo) analysis – Definition of key sub-surface uncertainties to be targeted for appraisal program-Generation of a robust range of production profiles and reserves estimates.
Current Challenges in Unitisation - The Nigerian Experience
Authors: Ajayi Olufemi A. , Otoh George
Published: February 2011

Unitisation enables the exploitation, as a single unit, of Oil and Gas deposits in fields/reservoirs straddling two or more parties’ mutual concession boundaries, under a single authority notwithstanding the respective permits or contract areas different contractual terms. This process, when completed, prevents disputes between the parties, which could potentially hinder efficient exploitation. Additionally, the practice of Unitisation enables sharing economies of scale and making best use of technical information, means and equipment. It also reduces / rationalizes costs and investments in order to optimally develop fields as a single unit.

Given the current legislation and legal framework for Unitisation in Nigeria, significant improvements have been observed from the regulatory institutions and other industry players, in the last 10 years. These include 2008 issued "Guidelines for Unitisation in Nigeria" by the Department of Petroleum Resources (DPR).

Although the concept of Unitisation is now commonplace in Nigeria, there are still challenges that need to be addressed. These include requirement for Unitisation for Brown – Brown fields (where both parties are already producing), assets/infrastructure valuation whereby both parties possess assets/infrastructure prior to Unitisation, and process of Reference Date (for commencement of Unitisation) issuance by DPR among others. The goal is overcoming challenges that cause delays in project delivery and shorten the process of Unitisation. Also, inefficient utilisation of resources, and the challenges of developing straddling fields are eliminated, as global energy demand and cost of supply increases.

This paper, will explore some options and potential solutions to these challenges faced in the practice of Unitisation in Nigeria. Some of the solutions proffered are in the area of inclusion of non-straddling reservoirs in a unit and consistency in interpretation when production exist prior to Unitisation by one or both of the licence(s).
Implications of Injection Water Capacity Limitations in Field Development in Deepwater Nigeria
Authors: Obidike Peter , Ekebafe Abraham , Uchenna Orekyeh , Areje Adegoke , Elozino Olaniyan , Onyema Ohabuike
Published: February 2011

The economics of deepwater oil field developments rely heavily on the availability of high oil production rate wells that can generate early income to pay for the high CAPEX invested in such field developments. In addition to the cash flow is the uncertainty that surround such high CAPEX developments. For example the influence of governments and policy changes leaves the investor no choice than to ensure early recovery of investment. To support the required high oil production rates, the reservoir pressures must be maintained to minimize the chances of breakout of gas in the reservoir in an under saturated system or production of gas cap gas in a saturated system.

Often times, the question is not whether to apply a reservoir maintenance scheme or doubts about the strength of the aquifer but when is the appropriate time to implement the water injection scheme and thus optimize the development for stakeholders both in terms of economics and ultimate recovery.

The choice of scheme to employ follows the decision to provide reservoir pressure support as part of reservoir management strategy. Water injection in the deepwater setting appear to be a preferable choice over gas given the ready availability of sea water and less complications in the operation of the injection system when compared to gas injection.

Further to the decision on the use of water injection for reservoir maintenance is the question of sizing of the injection facility to deliver the required amount of water for the field development. Subsurface and Project engineering teams most often depend on global industry knowledge especially the golf of Mexico to design the injection facilities. However occasions arise where the development plans and aspirations defer. For example, the sizing of the injection system may not have considered the complexity of the reservoirs nor the future development plans for nearby fields. Such occasions may result in ad hoc operational philosophy to optimize oil production.

This paper aims to put the shortcomings of water injection limitations in deepwater Nigeria in perspective, identify best practices in such instances and make recommendations for future development planning.
Modelling High Rate Fractured Injection in the Bonga Field
Authors: Okoh Ehimhen , Sathyamoorthy Sekhar , Ebitu Sophia
Published: February 2011

The Bonga field has produced more than 275 MMstb in the last 4 years, a major contributor to deepwater oil produced offshore Nigeria to date. High production rates are being sustained as a result of the pressure maintenance scheme based on waterflooding that was implemented from the onset of production. Fully treated seawater is injected from 13 subsea high rate water injector wells daisy-chained on two separate water injection lines. To date more than 370 MMbbls of treated seawater has been injected in the field.

High rates in water injector wells can only be achieved through fractured injection. Industry experience so far shows that matrix injection mode leads to declining well injectivity. However, for effective reservoir management, it is required that fractures created are not excessively large to cause integrity concerns on nearby seals, reservoirs and wells. Hence, it is necessary to predict the fracture dimensions for corresponding injection rates and pressures for effective waterflood management. The size (length and height) of an induced fracture depends on several parameters.

This paper describes the use of an in-house fractured injection tool for estimating lateral and vertical extension of waterflood-induced fractures in Bonga wells. History matching of field data is performed to calibrate the model. Information from Pressure Transient Analysis and well interventions is used to improve model prediction. The analysis shows that with continuous high rate injection, long contained fractures are created in these high Darcy sands. Prediction results are used to define operating envelopes for these high rate water injector wells, with rates constrained in some wells to prevent induced fractures breaching the top shale layer.