bluuebunny/crossref_metadata_2025 huggingface dataset:
Assessing Wellbore Integrity in Sustained-Casing-Pressure Annulus
Authors: Rocha-Valadez T.. , Hasan A.R.. R. , Mannan S.. , Kabir C.S.. S.
Published: June 2014

Sustained casing pressure (SCP), exhibited by many wells, is defined as any measurable casing pressure that rebuilds after being bled down, attributable to cause(s) other than artificially applied pressures or temperature fluctuations in the well. Gas leakage, leading to SCP, may occur through the poor cement bond between the casing and the formation, packer, and/or the casing itself. All safety regulators require SCP elimination. However, test-data analysis is mostly qualitative and limited to arbitrary criteria, thereby lacking consensus. This paper attempts to provide a theoretical frame and a model for quantitative analysis of SCP-test data.

Specifically, we adapted a model for SCP that is rooted in the transport processes of the system. The model accounts for mud compressibility and assumes gas is leaking into the annulus and migrating up the annular liquid column. Some robust assumptions about the transport processes allow for expressing the governing equation as a first-order, linear differential equation that is solved with appropriate boundary conditions. The resulting algebraic expression for the casing-pressure rise (Annulus A) with time is easy to apply. A comparison of the performance of the model with field data suggests that gas influx causes a casing-pressure (Annulus A) increase in wells.
Shale-Drape Modeling for the Geologically Consistent Simulation of Clastic Reservoirs
Authors: Alpak Faruk O. , van der Vlugt Frans
Published: June 2014

A set of algorithms, called the shale-drape function (SDF), has been developed that incorporates bounding shales (shale drapes) for channels, channel belts (also known as meander belts), lobes and lobe complexes in 3D geologic models used for reservoir simulation. Shale drapes can have a significant impact on the recovery efficiency of clastic reservoirs. Therefore, they need to be modeled when present in significant quantities (in general, more than 50 to 70% in terms of areal coverage). The function incorporates shale drapes into a geologic model with an iterative process that creates shale layers over the entire surface of reservoir objects and then places ellipsoid-shaped holes into shale surfaces until a desired areal coverage is reached. The workflow for application recommends to grid the simulation model along the boundaries of stratigraphic objects, thereby ensuring that the shales can be realistically represented in the fine-scale geomodel and preserved in the post-upscaling simulation model.
Assessing Economic Implications of Complexity in Geological Modeling and Simulation
Authors: Singh Harpreet , Srinivasan Sanjay
Published: June 2014

Economic forecast for assessing reservoir performance is a strong function of geological modeling. Complexity of geological modeling may vary from semivariogram-based models to multiple-point simulation technique. Semivariogram-based stochastic simulation techniques are less complex than multiple-point simulation technique in terms of the amount and type of reservoir information needed to generate the porosity and permeability maps.

This paper assesses economic implication of using geological models of varying levels of complexity. For this we compared the uncertainty in reservoir's long term economic performance obtained by using geological models with varying levels of complexity. Reservoir economic performance is assessed using both the real options valuation (ROV) analysis, a probabilistic approach, and discounted cash flow (DCF) based approach.

The results suggest that it may be appropriate to use simpler geological models for the forecast of volumetric flow rate uncertainty. We see that the economics in terms of ROV obtained from a simple geological model is not significantly different from that of a complex geological model. Similar results also hold true with DCF analysis.

This study could help answer the question of how much detail in reservoir models are necessary if the end objective is to obtain realistic assessment of net economic risk (which would be used to make correct decisions)?
Appraisal and Valuation for Proven Shale Play Acquisition Opportunities
Authors: Chorn L. , Bharali N. , Murali K.
Published: June 2014

Shale asset property consolidation, fractional acquisition of proven properties, and outright company acquisitions generate a growing demand for technical-economic appraisal support. Proven concept plays, attractive to larger oil and gas companies and investment firms, often have large amounts of geology and geophysical data, but may have limited production histories in as many as 100 wells within the regional play. Acquirers must address data management needs, secureaccess to experienced shale professionals, and meet timeconstraints to review, interpret, understand, and value the opportunity. The acquirer must validate the seller’s technical work and assessments, gather additional supporting technical data, develop an economic model from decline curve analyses (including CAPEX and OPEX insights), establish relevant transaction benchmarks, and qualitatively evaluate the operator’s capabilities.

Key components of the appraisal and valuation effort include setting technical and business metric thresholds, organizing key professionals’ work product and interactions, managing data inventory, validating existing analyses, filling in missing data with insights from analog plays, and consolidating results into actionable recommendations. The results of the appraisal and valuation exercise includes an itemization of positives, negatives, and residual uncertainties that the acquirer must incorporate into their portfolio evaluation process and estimate the value created, if the acquisition is consummated. This paper uses a recent successful acquisition to illustrate a workflow that compresses the time required to screen and evaluate a shale play acquisition in the US.
Reserve Technical Potential Management System: Key in Rehabilitation of Mature Field
Authors: Ruslan M. , Caretta F. , Artola R. G. , Gandolfo J. M.
Published: June 2014

The Reserve Technical Potential Management System (RTPMS) is divided into 5 main stages and associated together with the Petroleum Reserve Management System by SPE. The main aim by merging these two concepts is to improve understanding of the reserves pool and therefore provide a practical guideline on a standard definition for high level planning and day-to-day operations. The concept is being developed with major focus on the rehabilitation of mature fields where each barrel of oil counts and uncertainty, both technical and economical, are becoming more challenging at industry level. High decline in productivity and increased operational challenges are common issues for mature fields. Recurrently, lower recovery factors are mainly driven by reservoir characterization uncertainty and management, geological complexity, limited resources and operational efficiency. This paper addresses some of these challenges in an integrated manner.

Each stage is mapped and associated with the SPE Petroleum Reserve Management System, the project management control level, the time cycle (short: operation efficiency, medium : production optimization and long: reservoir management), a digital oilfield concept, the roles and responsibilities of the stakeholders, the technology groups and their key technologies. The five stages are defined as; 1) Actual Potential, 2) Operational Technical Potential, 3) Constrained Technical Potential, 4) Theoretical Technical Potential and 5) Ultimate Technical Potential.

The concept has been developed based on lessons learnt and best practices acquired in mature field rehabilitation projects.
The Value of Assessing Uncertainty in Oil and Gas Portfolio Optimization
Authors: Hdadou Houda , McVay Duane A.
Published: June 2014

It has been shown in the literature that the oil and gas industry deals with a substantial number of biases that impact project evaluation and portfolio performance. Previous studies concluded that properly estimating uncertainties will significantly impact the success of risk takers and their profits. Although a considerable number of publications investigated the impact of cognitive biases, few of these publications tackled the problem from a quantitative point of view.

The objective of this study is to demonstrate the value of quantifying uncertainty and evaluate its impact on the optimization of oil and gas portfolios, taking into consideration the risk of each project. A model has been developed to perform portfolio optimization using Markowitz's theory. In this study, portfolio optimization has been performed in the presence of different levels of overconfidence and directional bias to determine the impact of these biases on portfolio performance.

The results show that disappointment in performance occurs not only because the net present value (NPV) of the realized portfolio is lower than estimated, but also because the risk of the realized portfolio is higher than estimated. This disappointment is due to both incorrect estimation of value and risk (estimation error) and incorrect project selection (decision error). The results of the cases analyzed show that, for investors with high-risk-tolerance, moderate overconfidence and moderate optimism result in an expected disappointment of about 50% of the estimated portfolio. For investors with low-risk-tolerance, the same amounts of moderate overconfidence and optimism result in an expected disappointment up to 78% of the estimated portfolio. The value of reliably quantifying uncertainty is reducing the expected disappointment and the expected decision error. This can be achieved by eliminating overconfidence in project evaluation and portfolio optimization; optimism is reduced in the process. Consequently, overall industry performance can be improved because reliable uncertainty assessment enables identification of superior portfolios, with optimum reward and risk levels, and increases the probability of meeting expectations.
Decision Analytics, Value of Information, and Piloting in Unconventional Reservoirs
Authors: Bickel J. Eric
Published: June 2014

Suppose we plan to develop a field by drilling up to N wells. Each well i (= 1 to N) will produce an uncertain quantity of reserves Xi. We assume that the Xi are identically distributed with common mean m and variance s2 This is often reasonable, as companies view the development of unconventional reservoirs as a statistical plays; some wells will be profitable and others will not. Lacking an ability to identify the wells that fall into each category, a package of wells is drilled with the hope that the average reserves m will exceed some minimum threshold t.

We further assume that given m and s2 are known, the wells are probabilistically independent. Therefore, we assume the wells are independent and identically distributed (iid). In practice, the iid assumption means that (1) we do not have any reason to believe one location is likely to be more profitable than any other and (2) the drilling results at one location do not change our beliefs about the potential profitability of another location, given that m and s2 are known. If either m or s2 are uncertain then prior drilling results at one or more locations will tell us something about the future prospects for the field.
Estimating Long Term Well Performance in the Montney Shale Gas Reservoir
Authors: Dinh Vu P. , Gouge Brad A. , White Aaron
Published: June 2014

Establishing long term production decline in unconventional reservoirs is challenging due to the high degree of uncertainty associated with well and reservoir properties. When Arps’ hyperbolic rate decline method is applied in extremely low permeability reservoirs, we usually obtain b-parameter values higher than 1 which may lead to overestimation of future production. One practical way to constraint future production is to switch from hyperbolic to a terminal exponential rate decline at a specified time (a.k.a. "modified hyperbolic relation"). Since most Montney Shale Gas horizontal wells have not reached stabilized boundary dominated flow due to low matrix permeability, the difficulty with using this technique is that the terminal exponential decline rate cannot be established in advance and typically must be specified from experience.

This paper presents one practical approach to establishing the terminal exponential decline rate for the Montney Shale Gas in Canada. Using the analysis techniques proposed by Blasingame and Lee (1986), important formation characteristics can be estimated analytically from post transient exponential decline. By evaluating long-term production trends of existing vertical wells, reservoir pore volume can be determined along with other naturally-fractured reservoir characteristics such as matrix) fracture permeability ratio and dimesionless fracture storage. Since horizontal wells’ production performance is strongly influence by the same natural fracture reservoir characteristics, this easy to use approach provides a reasonable estimate of terminal exponential decline parameters.
The Relationship Between Operational Costs and Oil Prices: A Contribution for Probabilistic Economic Assessment
Authors: Hastenreiter L. , Hamacher S. , Montechiari J.
Published: June 2014

This article presents a probabilistic methodology for estimating the Net Present Value (NPV) of oil and gas production development projects. This methodology takes into account the uncertainties of important variables present in the economic evaluation, such as oil and gas production, prices, investments and operational costs. Furthermore, this paper aims to understand the impact of oil price change in the behavior of costs. It also presents a case study which allows indentifying and analyzing the results of the methodology implementation. The results show the importance of evaluating and quantifying the uncertainties in the economic appraisal, as well as the need to consider the effect of oil price changes. Hence, it points out an alternative to estimate the expect returns on investments according to a probabilistic approach, which can impact one of the most important variables for the economic project decision-making, the Net Present Value.
Make Better Decisions
Authors: Ambrose Jason , Monette Scott A. , Malani Sanjay
Published: June 2014

Declining global economic conditions and increased pressure to find new, affordable sources of energy create a turbulent macro environment for oil and gas companies. Stakeholders present conflicting goals of increased return on investment while simultaneously reducing risk and providing greater transparency into project performance. The traditional models of large scale investment into major capital projects can no longer guarantee success; instead, organizations must focus on capital management throughout a project's life cycle. Significant effort, time, and resources are invested in project delivery. However, poor decisions during the planning phases may result in loss of value during execution. By combining decision analysis tools and techniques with integrated, dynamic planning systems, companies are able to carefully manage their capital across the project life cycle to understand their costs, resources, and schedules. These companies benefit from increased collaboration leading to more informed decision making balancing risk and reward.

This paper presents an innovative method for evaluating and dynamically planning the development of uncertain upstream investments. It centers on a paradigm shift in the way upstream managers assess investments, toward an approach that incorporates decision analysis tools and techniques with integrated dynamic planning systems. Case study examples are provided to illustrate key principles.
Assessing Value of Test Wells in Developing an Unconventional Play – Decision Entropy Theory
Authors: Habibi Mahdi , Gilbert Robert B. , Lake Larry W. , McIntosh Patrick
Published: June 2014

Unconventional plays have considerable uncertainty in production and economics. This paper proposes Decision Entropy Theory to represent uncertainty in unconventional plays in an objective and defensible way. The motivation to develop this theory is to account for the possibility of events occurring that are beyond our range of experience. This theory characterizes uncertainty in the context of making a decision; the case of maximum uncertainty corresponds to the maximum entropy for the possible outcomes of the decision. Assessing the value of test wells before committing to developing a play with unconventional resources is used to illustrate the theory.

We pose the decision to develop an unconventional play in terms of the cost of development, the ratio of the return-on-investment for productive wells in the play, and the uncertain frequency of productive versus unproductive wells in the play. Results for the value of tests wells are obtained and provided graphically in non-dimensional relationships.

Significant conclusions are the following:

The probability distribution for the uncertain frequency of productive wells is important both for deciding whether or not to develop a play and for the value of information from test wells. It is unreasonable to assume that the probability distribution for the frequency of productive wells can be established based entirely on experience because that precludes the possibility of events beyond our experience. Such events can be particularly important with unconventional plays where experience tends to be limited. The value of test wells is enhanced when leaving open the possibilities for profit on a play with a small return-on-investment ratio and the possibility for loss on a play with a large return-on-investment ratio. There is a balance between relying entirely on historical data from analogous plays versus not relying on them at all. Within this balance, information for test wells at a new play can be combined with information from analogous plays to inform the decision about developing the new play. The value of test wells in a new play depends on the break-even frequency of good wells in the play; in the case of no information, this value is a maximum when the break-even frequency is 50 percent.
A Stochastic Techno-Economic Model for Multi-Target Exploratory Prospects, Including Tax Implications of Purchase Price
Authors: Cronshaw Mark , Lencioni Letha C.
Published: June 2014

Probabilistic analysis is commonly used for evaluation of exploratory prospects, where uncertainty exists about the prospect size. A common methodology is to estimate distributions for parameters used in volumetrics, perform stochastic simulation, and utilize discrete estimate(s) from the resulting resource distribution, prepare economic projections for these cases, and estimate a probability of success (POS) based on geoscientists’ judgment about various risk factors. The POS is multiplied times the discounted net present value (NPV) of the success case, while one minus the POS would be multiplied times the NPV of failure. These values are summed to yield the expected value. Alternatively, the POS can be incorporated into the probabilistic analysis, including risk factors in discrete distributions. Incorporating the economic calculation into the probabilistic analysis can capture all possible outcomes, including non-commercial discoveries.

This paper describes a stochastic model for valuation of an exploratory prospect, prepared in an Excel spreadsheet with the @Risk add-in. The model accounts for the U.S. tax implications of the purchase price. The purchase price is eligible for depletion in the event of exploratory and development success, but can be written off in the event of failure. The model allows for two target reservoirs, and the multiple possible outcomes of that exploration scenario. Several examples are presented, and will be compared with the method using only one or three economic cases.

This model was used to prepare an estimate of the net present value of an exploration prospect for income tax purposes. The model enables proper consideration of the multiple possible outcomes. Of key importance in the application for this relatively low POS prospect was the inclusion of the tax benefit of writing off the purchase price in the failure cases. This early write-off can offset the failure costs against other taxable income, which is a substantial economic benefit.

The importance of this work includes a methodology to properly account for the multiple possible outcomes with uncertainties not only in prospect size and productivity, but also in economic factors including oil pricing, exploration and development costs, and operating costs.
Unlocked Shale gas: Latin-American potential. A case study of Mexico and Argentina Case Study
Authors: Esther Escobar
Published: June 2014

Argentina and Mexico have been long-term natural gas producers, supplying most of their domestic gas demand. However, due to a decline in the production of their associated and non-associated gas fields in recent years, the gap between the production and domestic consumption of natural gas has widened.

An updated EIA 2013 assessment of shale gas resources per country ranks Argentina and Mexico as the second and sixth largest in terms of technically recoverable shale gas resources with risked most likely estimates of 802 Tcf and 545 Tcf respectively. The impact of these newly identified gas resources on future supply is a key question, of particular importance is whether shale gascould bring about a reversal in the current decline in gas production over the next few decades. In view of the large resources identified, renewing the energy policies in Argentina and Mexico could serve as the main driving force for unlocking shale gas production. In order to analyse both countries, natural gas market data available for the period 2011 to present, were reviewed. To examine the current situation of both countries, the following were analysed: the hydrocarbon law (related to gas production), the structure of the both markets, price incentives and fiscal regimes. This paper concluded that the main criterion which is likely to control shale gas development in either Mexico or Argentina, is the trend of the natural gas prices at which both countries trade. Model results demonstrate how the development of shale gas is relatively unattractive in Mexico due to it adopting Henry Hub gas prices. In contrast, a model for Argentina shows how the uplift in gas prices at wellhead has spurred shale gas exploration investment in Argentina.
‘Carry My Share’: Assessing the Impact of State Participation on Upstream Contractor Value
Authors: Ikezogwo Obiocha A. , Boodoo Sonya
Published: June 2014

In many host countries, the fiscal system governing petroleum resource exploitation allows the State, represented by its National Oil Company (NOC), to participate in petroleum projects. A common form of said participation is via the ‘carry’, in which the contractor ‘carries’ the NOC through one or more stages of the project, effectively shouldering the latter's share of costs. In this way, the ‘carry’ resembles a loan to the NOC by the contractor. Like any other loan, this has financial implications, and can significantly impact the contractor's view of upstream project economics.

The ‘carry’ mechanism is an important yardstick that should be considered in comparative analysis of petroleum fiscal systems. In this paper, we assessed the impact of NOC participation on contractor value, using a sample of twenty-five fiscal systems. For each regime, economic models representing ‘carry’ and ‘no carry’ scenarios were constructed, and evaluated using seven economic indicators. We observed that the existence of ‘carry’ does not affect overall project viability, but, in most cases, it reduces contractor value. Furthermore, we found that ‘carry’ skews project risk towards the contractor, by increasing maximum capital exposure. Finally, by comparing two different measures of Government Take (a key measure of the attractiveness of a fiscal regime), we demonstrate that including‘carry'as part of Government Take results in an increase in the State's share of resource rent.
A Probabilistic Approach to Reserves Booking and Evaluation in Early Development Fields
Authors: Huerta Quiñones Víctor A.
Published: June 2014

Technical recoverable volumes estimation and reserves booking are two of the most significant and complex tasks in the petroleum industry, since figures add value to company assets and/or the economy of a country. Both processes, which not always are quite compatible because of project maturity or non-technical issues, usually embrace uncertainty due to lack of information and different criteria of reserves auditors.

Conventional incremental deterministic approach ruled by guidelines of the Petroleum Resources Management System (PRMS-SPE/WPC/AAPG/SPEE) and the Securities Exchange Commission framework is quite restrictive to book for proved reserves of a field in an early development phase or few years of production history; in addition, 2P and 3P estimations are closely linked to current geological interpretation, and are not flexible to account for the whole uncertainties inherent to project at that level of maturity.

A new probabilistic approach has been proposed to provide consistency and confidence to conventional 1P, 2P and 3P deterministic estimations in recent gas condensate fields. The incorporation of strong descriptive statistics concepts in traditional probabilistic volumetric models, such as central limit theorem, dependency between model inputs (Bayes’ theorem), aggregation of volumes, as well as, the use of the standard error of mean, have given consistency to volumetric model outputs. These probabilistic calculations, adjusted to SEC definitions for proved reserves, and SPE standards, for 2P and 3P reserves categories, as well as, contingent resources, allows dealing with uncertainty inherent to a new field on development phase.
Integrated Economic Model for Evaluation and Optimization of Cyclic Steam Stimulation Projects
Authors: Frenette C. T. , Saeedi M. , Henke J. L.
Published: June 2014

The development of any hydrocarbon resource should be planned to maximize the net present value (NPV) of the asset to stakeholders, subject to any imposed constraints. For example, in the evaluation of a single oil or gas well on primary production, assuming no additional constraints, maximization of the NPV may be obtained by maximizing recoverable volume, production rate, and realized product price, while at the same time minimizing capital and operating costs, royalties, and taxes.

Maximization of the NPV of a thermal heavy oil project is significantly more involved than that of a single oil or gas well on primary production. This is due to the complex interplay of individual well production and injection profiles with field level production and injection constraints imposed by the central processing facility (CPF). In addition, for thermal heavy oil recovery methods such as cyclic steam stimulation (CSS), the scheduling of the production, soak, and injection cycles of the wells has a significant impact on the overall project NPV.

This paper presents the results of a study to maximize the NPV of a greenfield CSS project by incorporating a recently developed horizontal CSS analytical model with a new surface model and economic evaluation model developed specifically for this purpose. The integration of the sub-surface, surface, and economic models allows for the optimization of input parameters simultaneously across the models to maximize the NPV of the entire project.

The overall workflow and resulting optimized case will be summarized and discussed. In addition, stochastic simulation concepts are applied to the model to produce a distribution of results based on various input parameters. Stochastic simulations are already used in unconventional gas evaluations, and the authors believe that they will become an important tool to assist in the evaluation of thermal heavy oil projects due to the significant upfront capital cost and uncertainties associated with such developments.
The United Nations Framework Classification for Fossil Energy and Mineral Reserves and Resources – A Global Classification Standard for Energy Resources
Authors: Smith S. Tim , Ray Don
Published: June 2014

Governments, regulatory agencies, the petroleum and mining industries, the financial community, international organizations and professional societies worked together under the umbrella of the United Nations (UN) to develop a principles-based resource classification system -- United Nations Framework Classification for Fossil Energy and Mineral Reserves and Resources ("UNFC-2009") -- that is suitable for all extractive activities, whether mined as a solid or produced as a fluid through wells. The system is designed to be fully compliant with the SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS).

A key benefit of UNFC-2009 is that it provides a platform for harmonizing (mapping) classification systems in use around the world, and for translating volumes both within and between commodity sectors. Another benefit of UNFC-2009 is that it uses numbers instead of words for classification. Numbers transcend communication barriers created by differences in language and cultural references.

The system is designed as a three-dimensional framework where volumes are classified based on: (1) economic and social viability, (2) project status and feasibility, and (3) geological knowledge; however, it can also be represented in a practical, two-dimensional, abbreviated version. A task force formed by a UN expert group, the Expert Group on Resource Classification (EGRC), is studying the application of UNFC-2009 to classify injection projects. Work is also underway to extend the utility of UNFC-2009 to atomic energy and renewable resources. If successful, it will allow, for the first time, classifications and comparisons of projects across most energy sectors.
Cement Evaluation of Fibre-Reinforced Plastic Casing for EOR Observation
Authors: Edwards John , Kalyanaraman Ram Sunder , Renard Sandrine , Kuijk Robert Van , Froelich Benoit
Published: June 2014

Multiwell pilots are the final step of enhanced oil recovery (EOR) screening before the final investment decision. Data gathering is the primary purpose of any pilot, including data about the reservoir's response to the EOR method. A common technique for gathering data about spatial and temporal change in the reservoir resulting from injecting an EOR agent is time-lapse logging of an observation well positioned at some distance between the injectors and producers. Conventional observation wells are completed in cemented steel casing across the reservoir, and logged with nuclear measurements. However, fibre-reinforced plastic (FRP) casing is used instead of steel when a more sophisticated logging suite is required. For example, induction resistivity, crosswell resistivity, surface-to-borehole resistivity, and nuclear magnetic resonance are additional measurements that can be obtained if the casing material is nonconductive and nonmagnetic.

It is important to establish that the annulus of any cemented well is hydraulically isolating. This is critical for an observation well in an EOR pilot to ensure that the well is not short-circuiting the flow of injected fluids via annular channels. Cement evaluation of steel-cased wells has been a routine service since the 1950s, with four generations of tools developed to refine this measurement. There is less experience of cement evaluation behind FRP casing. An acoustic-based method of cement evaluation has been demonstrated in one FRP casing size and thickness with laboratory experiments in a water tank without cement. The variation in FRP casing manufacture and casing wall thickness means the result from this experiment is not universal. A field procedure has been developed to extend this initial experiment to any FRP casing sample, and any cement recipe, and to measure both cemented and free FRP casing. These field experiments will determine for a specific FRP casing sample and cement whether the acoustic-based method of cement evaluation will provide a valid cement log.
Dynamic Ranking of Multiple Realizations by Use of the Fast-Marching Method
Authors: Sharifi Mohammad , Kelkar Mohan , Bahar Asnul , Slettebo Tormod
Published: June 2014

One of the great challenges in reservoir modeling is to understand and quantify the dynamic uncertainties in geocellular models. Uncertainties in static parameters are easy to identify in geocellular models. Unfortunately, those models contain at least one to two orders of magnitude more gridblocks than typical simulation models. This means that, without significant upscaling, the dynamic uncertainties in these models cannot easily be assessed. Further, if we would like to select only a few geological models that can be carried forward for future performance predictions, we do not have an objective method of selecting the models that can properly capture the dynamic-uncertainty range.

One possible solution is to use a faster simulation technique, such as streamline simulation. However, even streamline simulation requires solving a pressure equation at least once. For highly heterogeneous reservoir models with multimillion cells and in the presence of capillary effects or an expansion-dominated process, this can pose a challenge. If we use static permeability thresholds to determine the connected volume, it would not account for how tortuous the connection is between the connected gridblock and the well location.

In this paper, we use the fast-marching method (FMM) as a computationally efficient method for calculating the pressure/front propagation time on the basis of reservoir properties. This method is based on solving the Eikonal equation by use of upwind finite-difference approximation. In this method, pressure/front location (radius of investigation) can be calculated as a function of time without running any flow simulation. We demonstrate that dynamically connected volume based on pressure-propagation time is a very good proxy for ultimate recovery from a well in the primary-depletion process. With a predetermined threshold propagation time, a large number of geocellular models can be ranked. FMM can be scaled almost linearly with the number of gridblocks in the model. Two main advantages of this ranking method compared with other methods are that this method determines dynamic connectivity in the reservoir and that it is computationally much more efficient. We demonstrate the validity of the method by comparing ranking of multiple geocellular realizations (on Cartesian grid with heterogeneous and anisotropic permeability) by use of FMM with ranking from flow simulation. This method will allow us to select the geological models that can truly capture the range of dynamic uncertainty very efficiently.
Steam Chamber Development and Production Performance Prediction of Steam Assisted Gravity Drainage
Authors: Wei Shaolei , Cheng Linsong , Huang Shijun , Huang Wenjun
Published: June 2014

Steam assisted gravity drainage (SAGD) is an effective technology to develop heavy oil reservoir, yet with large energy consumption and intense greenhouse emission. Therefore, it is important to predict the steam chamber development process and production performance of SAGD process. In early research, a lot of research has been conducted on the prediction of SAGD productivity analytically under some simplification. According to tens of numerical reservoir simulation results with STARS, we find that oil production rate is greatly linked to the steam injection rate. As to our knowledge, few studies have been published to build a relationship between them. In this paper, we propose a new analytical model to predict steam chamber development process and SAGD production performance under constant steam injection rate simultaneously. On the basis of previous numerical and experimental research, we assume that the steam chamber shape is a combination of two symmetrical parabolas or an inverted triangle. The oil production rate is expressed by the steam chamber expansion rate as a function of reservoir properties and injection parameters. An energy balance equation is employed to connect the steam expansion rate and heat loss rate to surrounding formation. Comparisons have been made between the new model results and STARS results for a specific super-heavy oil reservoir case in Canada and similarity is observed with the parabola-shape assumption. With the new proposed model, production performance, such as oil production rate, water cut and steam oil ratio, can be predicted.
Two-Dimensional Magnetic Resonance Study of Synthetic Oil Sands
Authors: Jones M.. , Taylor S. E. , Zeng H..
Published: June 2014

Understanding oil sand structure and recovery processes at the laboratory scale is important for generating accurate models to predict performance ‘in the field’. Magnetic resonance imaging and nuclear magnetic resonance (NMR) are powerful nondestructive, non-invasive tools that have been shown to be ideal for characterizing porous materials. Previous work using NMR to investigate heavy oil and bitumen sands has primarily focused on one-dimensional relaxation analysis. Whilst the spectra produced are sensitive to the confining geometry and fluid types, there is often overlap between relaxation peaks from different fluids with similar relaxation times. These peaks are often difficult to separate accurately. We present a 20 MHz, 1H NMR two-dimensional correlation spectroscopy study of a range of synthetic oil sands systematically prepared with varying compositions of bitumen, water, sand and clay.

These two-dimensional experiments couple nuclear spin relaxation or self-diffusion in one time period with relaxation or self-diffusion occurring during a subsequent time period. This results in the acquisition of proton population distributions as a function of longitudinal (T1) relaxation time and transverse (T2) relaxation time. This allows further, more accurate, discrimination of the fluids and their different physical environments within in the oil sands. The results can also potentially lead to improved wettability and viscosity analyses of heavy oils in-situ.

The results from the synthetic samples are then applied to natural core samples.
Analysis of In-Situ Combustion Performance in Heterogeneous Media
Authors: Hascakir Berna , Kovscek Anthony R.
Published: June 2014

Potential candidates for in-situ combustion (ISC) are screened in the laboratory by one-dimensional combustion tube runs or reaction kinetics experiments, or, ideally, a combination of both. While one-dimensional experiments are conducted at average reservoir conditions, reservoir heterogeneities may have an impact on the amount of fuel formed and, consequently, the amount of heat generated. Therefore, prior to field applications of any potential candidates, it is essential to understand the upper and lower limits of the reservoir rock and fluid properties, and how ISC functions within those limits. In this study, the effect of varying connate water saturation, initial oil saturation, clay content, permeability, and porosity are investigated with one-dimensional combustion tube experiments on different heavy crudes (8-20 °API) with asphaltene content ranging from 10 to 18 wt% for different reservoir rocks including carbonates and sandstone. Process dynamics for good and poor ISC candidates are discussed in terms of effluent gas composition, temperature profiles and histories, total experiment time, oil recovery, behavior of fluid (oil, water, steam, and gas) front movements, and the level of oil upgrading at different reservoir conditions. Fuel consumption along with air requirements are analyzed for each experiment analytically. For good ISC candidates as identified by laboratory screening, the reservoir conditions that may lead to poor ISC field performance are estimated. It is observed that the reactivity of reservoir rocks at elevated temperatures (in the presence of oxygen) and the initial oil saturation are two important parameters that influence the fate of ISC. The findings considerably advance our understanding of field-scale ISC through the evaluation and interpretation of experimental data for different reservoir conditions.
How Does the Incorporation of Engineering Knowledge Using Fuzzy Logic during History Matching Impact Reservoir Performance Prediction?
Authors: Mirzabozorg Arash , Nghiem Long , Chen Zhangxin , Yang Chaodong , Li Heng
Published: June 2014

Population-based optimization algorithms are shown to be excellent candidates for improving the speed and solution diversity of history matching and optimization workflows, based on their successful track records for solving real-world problems.

The incorporation of reservoir engineering knowledge within these workflows, however, has been somewhat neglected. In particular, there is a lack of capability for guiding the optimization algorithms to specific regions of the search space. In a previous study, we introduced a framework for helping reservoir engineers incorporate their knowledge into history matching and optimization frameworks, by coupling a rule-based fuzzy system with a population-based sampling method.

The question is how the use of this type of information in history matching affects the performance of the reservoir study during the prediction stage. This paper investigates the effect that the incorporation of reservoir engineering knowledge during the history matching of the Teal South model production data has on reservoir performance in the prediction stage.

Two scenarios are considered. In Case I, we augment the history matching with reservoir engineering knowledge and then produce a forecast. In Case II, production data is history matched using differential evolution (DE), without fuzzy-logic-based engineering knowledge, then a forecast is produced

The results show that incorporating engineering knowledge of the reservoir under study during the history matching process can significantly reduce the uncertainty in the forecast, compared with the case where unrealistic parameter value ranges are used.
Physical and Numerical Modeling of Capillarity and Aqueous Phase Saturation Effects on the Rate of Solvent Mass Transfer in Boundary Layer in Heavy Oil Reservoirs
Authors: Ahmadloo F. , Asghari K. , Henni A. , Freitag N.
Published: June 2014

Solvent injection has emerged as a recovery technique in low pressure and shallow heavy oil reservoirs in cold systems or in combination with steam in steam-based thermal processes. The performance of solvent-based processes strongly depends on the rate of mass transfer in the boundary layer on the edge of solvent and/or steam chamber. Therefore, understanding of the mass transfer phenomena is required for realistic prediction of the performance of solvent-based or solvent-assisted processes. This study was designed to investigate the capillarity and aqueous phase saturation effects on the rate of mass transfer occurring in the boundary layer on the edge of the solvent chamber. In this study, a new experimental approach was designed and developed to eliminate any disturbance in the boundary layer to experimentally simulate the gravity drainage process in vapor extraction process at two different drainage heights. The porous media and oil-solvent characteristics required for history matching study were determined by measuring the capillary pressure and pore size distribution of sand packs, as well as conducting a complete phase behavior study to determine the properties of the oil-solvent system in a wide range of solvent concentrations. Total number of 12 experiments was conducted in three different sandpacks with different pore size distributions, but similar range of permeabilities (i.e., 5.1-6.5 D) to investigate the effect of capillary forces on the mass transfer phenomena.

Conducted analytical and numerical modeling showed that the effective diffusion coefficient was in the range of 4.91×10-8-1.10×10-5 cm2/s. In absence of immobile water saturation, effective diffusion coefficient was in the range of 4.91×10-8-7.89×10-6 cm2/s. In presence of immobile of aqueous phase saturation, the effective diffusion coefficient varied between 2.96×10-6 and 1.10×10-5 cm2/s. The comparison between the calculated effective diffusion coefficients and reported molecular diffusion in literature by different researchers confirmed that the velocity-dependent term in convective dispersion does not play a major role at higher capillarities in heavy oil systems, i.e., lower permeability range compared to other studies (i.e., >100 D). This study highlights the need for selection of a realistic mass transfer coefficient for the simulation of the performance of the solvent injection processes.
Gas Recharging Process Study in Heavy Oil Reservoirs
Authors: Zhang Jihong , Kantzas Apostolos
Published: June 2014

With the increase of demand for crude oil, heavy oil production becomes an increasingly important crude source for the energy industry. Non-thermal recovery methods, as a supplementary technique, hold the key for exploitation of these depleted or nearly depleted thin heavy oil reservoirs1. This paper focuses on gas recharging processes study for post-cold heavy oil production.

Although there is a diverse research effort on improving oil recovery ongoing for years, most of the experiments to date were conducted using small-scale core samples. It is always difficult at the laboratory level to conduct experiments at real representative field conditions, but larger - scale experiment can provide more realistic conditions15 compared to the reservoir scale. This is very helpful in understanding the prevailing mechanisms which may occur in the reservoir. To the best of our knowledge, the longest cores2-14 which have ever been used in the past are two 18m in length cores (glass beads and sand packed separately) tested by Goodarzi and Kantzas3,5 and Shi and Kantzas4.

This study involves three post-cold heavy oil production processes: CH4 recharging and depletion, CO2 and C3H8 huff-puff, and C3H8 flood. To generate data that is a step closer to reservoir scale, the two 18m long cores mentioned above and one 1.5m sand-packed core were used for testing. The mechanisms of each process were investigated. NMR and GC techniques were applied to help better understand production mechanisms. CT-scan was also used as the tool to monitor the core saturations before and after each process on 1.5m core. Density profiles as a function of core length were investigated. An attempt was made to use the results from short-core tests to explain the long-core results. The effects of core length and permeability on oil recovery were also compared and discussed. Multiple parameters were monitored and analyzed, such as pressure and temperature variations along the core, injected and produced gas composition, produced oil viscosity and water cut, core density before and after each process etc.