bluuebunny/crossref_metadata_2025 huggingface dataset:
Pore Network Modeling of Two Phase Flow in Vuggy Carbonates
Authors: Akin S. , Erzeybek S.
Published: June 2014

Carbonate reservoirs have more complex structures than silicate reservoirs because of depositional and diagenetic features. Secondary porosity enhancements due to fracturing or dissolution processes result complex porosity systems and thus complex flow patterns. Carbonates may contain not only matrix and fracture but also the vugs and cavities that are irregular in shape and vary in size from millimeters to centimeters in diameter. Although many of these vugs appear to be isolated from fractures, the mechanism of oil recovery from vugs in such a system is highly dependent on the location of the vugs and connections of the vugs to the matrix.

Studies on pore network models of carbonate rocks available in literature generally consider regular grain lattices, disregarding secondary porosity features. In this study, two phase flow in vuggy carbonates was studied by developing a novel pore network model. The constructed model consists of matrix and vug sub-networks. Matrix blocks were constructed by pores with triangular cross-section and pore throats with circular cross-section where as vugs were represented by square cross-sections. By distributing pore and pore throat radii randomly, a spatially uncorrelated model was developed. It was observed that this model can successfully simulate primary drainage and secondary imbibition recovery processes like snap-off, piston like advance and pore body filling. Comparison of pore network results and several published experimental results showed the uses and applications of the proposed pore network model. It was concluded that this novel pore network model design successfully represents two phase flow in a vuggy carbonate rock.
Matrix-Fracture Transfer Function in Dual-Medium Flow Simulation: Review, Comparison, and Validation
Authors: Abushaikha Ahmad S. A. , Gosselin Olivier R.
Published: June 2014

Most of porous naturally fractured reservoirs present a two-timescale flow-system, due to a two-scale heterogeneity which cannot be modelled explicitly, nor homogenised in reservoir simulation models. When the only flowing domain is the fracture network, and when the accumulation lies in porous and low permeable matrix blocks, the rate of exchanges between the two domains drives the recovery of such reservoirs. So called dual-porosity simulation models must incorporate an adequate transfer function between fracture and matrix in order to predict the recovery mechanisms for an optimal reservoir management. This is still true for dual-porosity / dual-permeability models, where the matrix domain is also flowing but at lower velocity.

During the past 40 years until recently several formulations have been proposed. In order to review, compare and validate some of them, this work first analyse the main recovery drivers in two-phase systems, like drainage and imbibition under capillary and gravity forces, on the basis of explicit (single-porosity) simulations of flows between fracture and a single matrix block on a fine mesh, characterised by the final value and the kinetics of the recovery. Varying the main dynamic parameters these simulations give a set of reference cases to benchmark the dual-medium models, like the classic Kazemi transfer function, the Quandalle-Sabathier one, and a new formulation recently proposed by Blunt et al. These dual porosity single-block transfer functions are easily discretised in time and coded.

The main findings are the disqualification of Kazemi formula, even with a gravity term, to represent any mechanism where the gravity is not negligible, especially in mixed-wet water-oil systems. Quandalle-Sabathier and Blunt transfer functions perform better, but the gravity forces remain difficult to be captured. The two first transfer functions are available in some commercial flow simulators, and their results on the same set of cases are consistent.
Distributed Unstructured Grid Infrastructure for Complex Reservoir Simulation
Authors: Fung Larry S. K. , Dogru Ali H.
Published: June 2014

It is now standard practice to use reservoir simulation as an everyday tool for better engineering and management of oil and gas fields. Modern reservoir simulation must be comprehensive in the treatment of complex reservoir processes, complex geology, intelligent maximum reservoir contact (MRC) wells, and production systems. For the more mature giant oil fields, significant volumes of detailed data are available. It is critical to maximize the use of these data for field planning in order to optimize recovery. Nowadays fast inexpensive parallel computers are widely available, modern reservoir simulators can exploit parallelism effectively such that modeling can be done at the desired scale and speed for better and timelier reservoir management. Simulators must also have the flexibility to use the general structured or unstructured grid systems for any combination of complex geology and recovery processes.

To handle all these complexities in a massively parallel environment, we have developed in Saudi Aramco's in-house reservoir simulator POWERS a distributed unstructured grid infrastructure (DUGI). DUGI is the parallel data structure and algorithms which constitutes the simulator's nerve center. Typical complex models for giant fields can have tens to hundreds of millions of grid cells, handling hundreds to thousands of wells, including some complex MRC wells. It can contain geologic features such as faults, pinch-outs, and fracture and multimodal porosities, described as the multiple porosity multiple permeability (MPMP) system. Both structured grids, with irregular multilevel local grid refinements (LGR) and unstructured grids can be used to resolve local reservoir or well geometry, and to model dynamic near-well coning behaviors. DUGI unifies the management of all these complexities into a consistent, scalable, and extendable system. It is designed to be modular such that data complexity and communication management are hidden from the rest of the simulator. This enhances simulator extensibility for ongoing feature development. Elements of DUGI will be discussed and examples of simulation models and results provided.
Advanced Engineered Fiber Technology - A Novel Solution to Cure Lost Circulation During Drilling: Pakistan Case History
Authors: Priening Peter , Ali Muhammad , Jaffery Maimoon , Salazar Jose , Jain Bipin
Published: June 2014

Losses while drilling are a serious concern to oilfield industry. Loss of expensive drilling fluid increases the overall cost of the well. Rig time spent curing the losses can represent significant cost overruns for the well. In extreme cases well control may become an issue.

The general practice to control losses starts from diagnosis of the cause. The common solutions to manage the loss circulation problem include drilling fluid treatments involving decreasing the density, controlling the viscosity and addition of lost circulation materials (LCM), controlling the drilling parameters, and placement of cement plugs.

This paper will discuss the treatment of drilling fluid with Advanced Engineered Fiber (AEF), the mechanism of action of AEF and its successful application as a solution for lost circulation in Pakistan.
Applications of Rotary Steerable in Low Cost Environments
Authors: Riyami M. , Edwards J. , Vache E. , Ojeiduma O. , Darwish W. , Johnston S.
Published: June 2014

The hydrocarbon basins in the Sultanate of Oman are in the desert where rig rates are low. This is not the typical environment for sophisticated drilling systems such as rotary steerables. However there are a number of niche applications where the use of this technology makes business sense. This paper will describe each application, explaining how a particular problem was solved with the use of rotary steering. Some of these applications are more unusual than others. For example one application is efficient directional drilling in hard abrasive layered formations of S-shape and J-shape profiles. Another is drilling buildups to precise horizontal landing depths, or drilling absolutely vertical holes in wells that have long heavy-wall liner sections that are run with inner strings and mechanical-set liner hanger packers. The consequence of a dog leg has been a liner that would not go down, but too heavy to retrieve. The rotary steerable applications also include assisting the acquisition of geological data. For example drilling extended reach smooth boreholes in fractured carbonate so they can be logged with imaging tools conveyed on drill pipe that can not be rotated. The measure of success, and a large part of the remuneration, is based on the imaged meterage not drilled meterage. These wells were drilled with an inclination-hold feature that kept the trajectory as straight as possible. Another geological example is the use of rotary steerables to accompany an azimuthal deep reading measurement used to geosteer the well. The elimination of sliding removed the blind zones that are a consequence of azimuthal logs, and the near-bit inclination helped the directional driller avoid over steering when the geosteering team requested an inclination change.
Utilizing Infrared Meters to Cost Effectively Monitor Water Cut on Horizontal Wells
Authors: Al-Saiyed Muhammad A. , Warsi Syed A. , Phillips James E. , Lievois John
Published: June 2014

The success of field monitoring and management depends on the accuracy and precision of the data gathering quality. A major parameter is the water cut value. The range of methods to measure and obtain the water cut values varies from conventional to high technical. Providing a means for continuous monitoring provides the information to take corrective action in a timely manner to better manage expensive well assets by maintaining well potential, managing water conformance and increasing the well life.

Saudi Aramco's traditional well testing practices, utilizing a test trap at a GOSP, limit the information available due to the frequency of test trap availability on a per well basis. This usually exceeds one month or more. Test trap data has inherent error built in due to averaging and human error. However, high tech real time water cut monitoring systems can provide the needed frequency and precision. Choosing the right application depends on how much data is needed and how accurate the data can be. In considering the methodology for obtaining water cut data, accuracy, data transference and cost play major roles.

Needless to mention, the drilling cost is significantly high when it comes to high potential complex multilateral and MRC wells. The expenditure for such wells can not be recovered if the wells die due to high water cut that goes unnoticed due to lack of data. Real time water cut monitoring can significantly reduce the number of such dead wells by providing the data to implement corrective action in a timely manner. This paper presents that how the infrared meter provides cost effective mean to monitor water cut for expensive complex wells.
An Integrated, Innovative Solution to Optimize Hydrocarbon Production Through the use of a Workflow Oriented Approach
Authors: Gutierrez F. , Bouleau C. , Howell A. , Gehin H.
Published: June 2014

Today's hydrocarbon environment requires depth of knowledge and expertise combined with technology innovation and integration across the various disciplines involved in the Reservoir Management cycles going from exploration to production, in order to increase production, reserves and improve operational efficiency.

An integrated approach including People, Process and Technology is necessary to break the barriers between the various reservoir management cycles - operations - production optimization and field management, and to improve the maturity of information to knowledge. Engineering processes related to each reservoir management cycle need to be accelerated by the implementation of automated/ & interactive workflows, integrating various levels of field data frequency with petrotechnical processes, that can help in operational efficiency, leaving more time for a more proactive engineering analysis of problems and solutions. A successful workflow approach ensures that the hydrocarbon's decline curve is mitigated with higher ultimate recovery. Also, the integration of data with numerical and analytical reservoir and well models, through workflows, helps to bring more efficiency in the field planning cycle in order to establish proper Enhanced Oil Recovery (EOR) or in-fill drilling plans to increase recovery factors.

The purpose of this paper is to show how workflow oriented solutions, within the context of the Digital Oilfield, have helped increase production, ultimate recovery factors and operational efficiency in various types of operational environments, and i.e. water flooding, Water Alternating Gas (WAG) and gas lifted fields.
Probabilistic Subsurface Forecasting - What Do We Really Know?
Authors: Wolff Martin
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

The full manuscript of SPE 132957, ’Probabilistic Subsurface Forecasting,’ is available as a supplement to this article.

Abstract

The use of single-valued assessments of company portfolios and projects continues to decline as the industry accepts that strong subsurface uncertainties dictate an ongoing consideration of ranges of outcomes. Exploration has pioneered the use of probabilistic prospect assessments as being the norm, in both majors and independents. Production has lagged, in part because of the need to comply with US Security and Exchange (SEC) reserves-reporting requirements that drive a conservative deterministic approach.

Look-backs continue to show the difficulty of achieving a forecast within an uncertainty band as well as the difficulty of establishing what that band should be. Ongoing challenges include identifying relevant static and dynamic uncertainties, efficiently and reliably determining ranges and dependencies for those uncertainties, incorporating production history (brownfield assessments), and coupling subsurface with operational and economic uncertainties.

Despite these challenges, none of which are fully resolved, a systematic approach based on probabilistic principles [often including design-of-experiment (DoE) techniques] provides the best auditable and justifiable means of forecasting projects and presenting decision makers with a suitable range of outcomes to consider.

Introduction

Probabilistic subsurface assessments are the norm within the exploration side of the oil and gas industry, both in majors and independents (Rose 2007). However, in many companies, the production side is still in transition from single-valued deterministic assessments, sometimes carried out with ad-hoc sensitivity studies, to more-rigorous probabilistic assessments with an auditable trail of assumptions and a statistical underpinning. Reflecting these changes in practices and technology, recently revised SEC rules for reserves reporting (effective 1 January 2010) allow for the use of both probabilistic and deterministic methods in addition to allowing reporting of reserves categories other than ’proved.?? This paper attempts to present some of the challenges facing probabilistic assessments and present some practical considerations to carry out the assessments effectively.
Increasing Oil Field Productivity Work Processes / Workflows in Digital Oil Fields
Authors: Pande Anil
Published: June 2014

As has already happened with most other industries in the past decade, the use of workflows in the E&P industry has only recently become increasingly prevalent. However, the way workflows are used in actual production operations is fundamentally different from other industries. The benefits of workflow in the E&P industry can lead to increased production and lower operating costs, and better use of scarce manpower resources, as discussed in the paper.

For workflows to be used in the E&P industry there are many important dependencies that must already be in place, based on the life of the asset as well as its maturity level. These range from process automation, data sources, and integration amongst others. In order to implementation a workflow within E&P, the steps needed to create and validate the workflow, taking an example such as production surveillance is covered.
Drill String Vibration Mitigation During Simultaneous Drilling and Hole Enlargement
Authors: Mancini Stefano , Hitchcock Graham , Opsahl Jørn , Servaes Luk
Published: June 2014

Drill string vibrations (torsional, axial, and lateral uncontrolled movements) can create issues with equipment, drilling performance and wellbore quality. With respect to equipment, prolonged excessive drill string vibration exposure can lead to fatigue failure such as drill string ‘twist off’, downhole tool breakage, shorter mean time between failure (MTBF) for measurement-while-drilling (MWD)/logging-while-drilling (LWD), and, in general, for directional drilling components. In rotary steerable drilling, a moderate to high drill string vibration can result in poor directional control, reduced penetration rate, and loss of time. This can result from reactive changes in drilling parameters intended to reduce detected drill string vibrations. Wellbore quality can suffer if the vibrations cause the bit to not drill a smooth borehole.

Simultaneous drilling and hole enlargement are sometimes associated with drill string vibration because of complex bottomhole assembly (BHA) dynamics involved in creating two hole sizes. Sources of drill string vibration during hole enlargement can be the drill bit, hole enlargement tool, or BHA. Mitigation of drill string vibration with respect to hole enlargement tools is of major interest because this can lead to reduced drilling costs, longer tool life, and improved wellbore quality.

This paper discusses specific expandable hole enlargement tool technologies that contribute to a reduction of vibration levels. Case history data is used to demonstrate these technologies, which have been shown to minimize drill string vibration during drilling and simultaneous enlargement operations, leading to the successful completion of well objectives.
Different Applications of Expandable Screens Through Three Case Studies
Authors: Furgier Jean-Noel , Souilah Ryad , Delattre Eric , Bourgoin Sébastien
Published: June 2014

Over the last years, expandable screens technology has become more mature and many oil and gas wells are now equipped with such sand control. This paper intends to present typical applications through three case studies.

The first case regards a gas well in Indonesia, where gas reserves are found in many thin layers spread over several hundreds of meters. Traditional sand control methods do not allow flexible and cost effective protection of many thin layers. Expandable screens were installed in a cased hole after a work-over with the aim to maximize gas reserves despite weak sand formation. The paper addresses the erosion concern related to this configuration.

In the second case, an old oil well in Cameroon was side tracked in order to reach marginal reserves. Frac-packing, preferred sand control method in Cameroon, was not practical considering the small drilling diameter, the high well angle, the dependency to stimulation boat availability and the economical constraints. Instead, expandable screens were installed in open hole, allowing cutting the cost down while providing very good well performance. Expandable screens open new opportunities to access additional reserves that were not economical with traditional technology.

At last the third case demonstrates the feasibility of utilizing expandable screens in a high profile deep water development in Nigeria. The paper describes three water injection wells where expandable screens were successfully installed in an open hole, and addresses the challenging deployment from a floating rig.
Evolution of the Event Solution Process: A Fully Integrated Approach to Reservoir Studies Delivering Solutions with Clarity on Uncertainty, Risk and Mitigation
Authors: Elrafie Emad , Hogg Martin , Abbas Tariq
Published: June 2014

In this paper, we present an update of the highly successful Event Solution process (SPE 105276, The Event Solution; a New Approach for Fully Integrated Studies Covering Uncertainty Analysis and Risk Assessment).

The Event Solution is a short, intensively collaborative, multi-disciplinary field development optimization study approach that compresses complex, multi-year, study decision cycle times into weeks / months with increased clarity and detail on a wider range of development options, under uncertainty. The Event Solution is a highly successful study approach that creates significant value added synergy (understanding, decisions, technical and business) among all stakeholders (technical professionals, managers, executives and partners). Project results are faster with more qualified decisions (operational, tactical, strategy and portfolio) that encompass the complexity and diversity of multiple project realizations under uncertainty.

Successfully employed on 14 mega Saudi Aramco projects since late 2006, this paper illustrates the significance and the impact of Event Solution project results in terms of improved holistic reservoir understanding, field development decisions, risk and mitigation, under uncertainty. Higher original oil in place (OOIP), increase reserves and longer production plateaus are examples of Event Solution success.

This paper describes the innovative Saudi Aramco Event Solution approach to jointly co-manage and model uncertainty and risk through an integrated static, dynamic and economic field development process. The Event Solution is compared and contrasted with other industry approaches, illustrating study approach differences and benefits. The paper also summaries the steps to implement an Event Solution approach in scalable manner in different sized companies.
Proactive Indicators To Control Risks in Operations of Oil and Gas Fields
Authors: Johnsen S.O.. O. , Okstad E.. , Aas Andreas L. , Skramstad T..
Published: June 2014

Because of the increased need for oil and gas, new and more-demanding oil fields must be explored in sensitive and challenging areas. Exploration of expert knowledge and new technology must be employed in these challenging situations. This collaboration and use of new technology introduces new ways of operating oil and gas fields. These new practices are often called "field of the future" or integrated operations (IO). These new practices are being implemented on the Norwegian continental shelf, leading to increased hydrocarbon recovery and changes in operations and maintenance. These practices may impact health, safety, and environment (HSE), but should not increase the risks of major accidents or influence HSE in a negative manner.

In this paper, we are suggesting a set of proactive indicators to ensure that risks are controlled when IO is implemented and operated. A proactive indicator is used as a measure of risk, to be controlled in risk management. The indicators have been developed on the basis of analysis of accidents, exploration of theory, and interviews and discussions in collaboration with the oil and gas industry.

Our suggested approach is to develop and explore indicators in close collaboration with key stakeholders to increase understanding and control of the relevant risks. Resilience and successful recoveries are not sufficiently explored in the reviewed accident reports, thus accident investigations should include reflections on reasons of successful recoveries and why the incident or accident did not have greater consequences.

The three most important causal factors of incidents seem to be poor design and poor validation of equipment, poor risk analysis of critical operations, and deviations from established procedures. A causal factor important in remote operations is miscommunication between actors during critical operations. Several proactive indicators are suggested, among them the level of exploration of safety cases during design and risk perception among stakeholders involved in operations. The indicators of remote operations should be a measure of shared communication and a measure of shared risk perceptions when critical tasks are distributed.

To validate the indicators, we are correlating the indicators with actual HSE levels. In addition, the indicators should be correlated to indirect measures (e.g., safety culture and risk perceptions) where appropriate.
An Organizational Approach to Malaria Protection: Balancing Precision and Practicality, Expert Panel Recommendations
Authors: Shallenberger Leba G. , Dockins Richard O. , Diara Malick
Published: June 2014

Global mobile workers risk serious disease and death from malaria while it is a curable and preventable disease. Organizations sending workers and their families into malarious areas are challenged by implementing efficient and consistent malaria control programs in the face of conflicting opinions, recommendations and perceptions regarding the necessity of malaria controls, especially regarding the use of chemoprophylaxis medications. Many of the issues related to malaria chemoprophylaxis have not been and are not likely to be studied in well-designed, randomized, double blinded clinical trials. In addition, country regulations differ and conflicting advice is provided by different health workers. To standardize advice and recommendations on malaria chemoprophylaxis, a list of issues was developed from questions frequently asked by managers, employees and contractors. During a two-day workshop, a world-renowned expert panel with extensive professional experience in infectious diseases, travel medicine, occupational medicine and health education, discussed the issues while reviewing the relevant literature and sharing their practical experience, to provide sound technical guidance. This paper provides scientific evidence-based malaria prevention guidance, balancing the precision of malaria protection with practical recommendations for chemoprophylaxis use, based on immune status and destination factors. The panel endorsed continued long-term use of chemoprophylaxis by individuals categorized as non-immune, traveling in high risk plasmodium falciparum areas. Specific guidelines were recommended for travelers to Mexico, Papua New Guinea and India. Guidance for travelers switching back and forth between various medications was provided to help individuals maintain protection and reduce the risk of adverse health affects from multiple drugs. Recommendations for offering medication breaks for offshore workers were not strongly endorsed due to unpredicted travel through high risk onshore locations and the difficulties in being able to effectively communicate and apply these guidelines.
A Four-Step Biotreatability Protocol for Crude Oil Impacted Soil
Authors: Hoffmann Rob , Bernier Rene , Smith Schaun , McMillen Sara
Published: June 2014

Bioremediation is often the preferred method for remediating crude oil impacted soil at exploration and production facilities because it is proven, cost-effective, robust, and performed on location. However, not all crude oil impacted soils are amenable. A four-step protocol, including predictive equations, has been developed to assess the feasibility of ex-situ bioremediation for crude oil impacted soil, enabling site managers to potentially forego expensive and time consuming biotreatability trials. First, representative samples are tested for conditions which could preclude bioremediation or necessitate pre-treatment, special management, or upfront lab treatability studies. The source crude and soil-based residual hydrocarbons are geochemically characterized to determine the inherent biodegradability of the crude and amount of hydrocarbon that has already been passively biodegraded or removed by an abiotic mechanism such as volatilization. A database of first-order rate constants characterizes the biotreatment kinetics. Compositional and rate data are used to estimate the duration of treatment and endpoint achievable by ex- situ bioremediation in steps 2 and 3. The predictive endpoint equation was derived from first principles, empirically corrected using field-scale data, and validated at full-scale for source condensates and crude oils ranging from 14° to 45° API. The degree of validation suggests the predictive equations are suitable for making decisions on bioremediation potential, thereby eliminating the need for lab and pilot treatability studies in many cases. If the duration and extent of removal predicted would fulfill the project's objectives, the final configuration (land treatment or composting) is selected in step 4 considering schedule and spatial constraints and the properties the bioremediated soil needs to possess to support the designated end use. As with any predictive methodology the practitioner must exercise caution to identify any confounding factors which could constrain the rate or degree of removal. This paper will present the biotreatability protocol, predictive equations for inferring bioremediation feasibility from compositional information, and other lessons learned from crude oil bioremediation projects performed over the last 20 years.
Integration of Ergonomics Studies into the Design Process: A Case Study in Petroleum Research Laboratories
Authors: Bittencourt J. M. , Carvalho L. B. , Duarte F. J. , Penteado E. V.
Published: June 2014

Integrate health and safety issues of workplace into design of new installations is a challenge for design engineers. The integration of ergonomics studies into design process is a proven strategy to achieve this challenge. The case presented reports the experience ergonomics integration after the basic project for new chemical laboratory facilities for petroleum research center at a Brazilian petroleum industry. The evaluation was based on usability concepts and identification of usual work situations; it was developed over the actual activities of 23 laboratories about to be transferred to a new building under construction. Due to the late integration of ergonomics into the design process, there were limited possibilities of interfering in design decisions, but still, many contributions were made to improve work conditions regarding equipment specification as laboratory bonnets, workbenches, dispensers for contaminated material and work stations.

The main recommendations made to improve work conditions at the new petroleum research facilities. The experience related may be applied by design engineers to improve new facilities projects; ergonomists working in laboratory environments.

The recommendations presented shows that ergonomic studies are not related to worker needs, but to activity needs. Upon confronting the basic project with the activities to be performed in the new space, it was ascertained that distributing equipment according only to security norms creates incompatibilities if the activity to be developed is not taken into account. Those incompatibilities may cause accidents, hinder access for equipment maintenance, provide insufficient space for contaminated material disposal and provide super estimated or overestimated space to develop laboratorial activities.

The earlier integration of ergonomics studies into the design process can prevent most of those incompatibilities. The consequence of late integration entails in the impossibility of correcting problems reproduced and which consume time and resources in reviewing project aspects. The significance of this paper is to relate the experience, so it can be applied by design engineers at future developments of new petroleum research laboratories and stimulate the integration of ergonomics into the design process so health and safety issues can be integrated in design process.
Impact of Water Dynamics in Fractures on the Performance of Hydraulically Fractured Wells in Gas-Shale Reservoirs
Authors: Cheng Yueming
Published: June 2014

Slickwater fracturing has been increasingly applied to stimulate unconventional shale-gas reservoirs. Comparing with crosslinked fluids, slickwater used as a fracturing fluid has several advantages, including low cost, a higher possibility of creating complex fracture networks, less formation damage, and ease of cleanup. An enormous amount of water is injected into the formation during the treatment. Even with a good recovery of injected water from flowback, large quantities of water are still left within the reservoir.

The dynamics of the water phase within the created hydraulic fractures and reactivated natural fractures (induced fractures) has significant impact on both short- and long-term performance of a hydraulically fractured well. The dynamics of the water phase within fractures is controlled by many mechanisms, such as relative permeability, capillary pressure, gravity segregation, and stress-sensitive fracture conductivities. In this paper, reservoir-simulation models for a generic gas-shale reservoir are constructed to investigate the changes of water-saturation distribution in fractures over time during production and their impact on gas-production performance. It is demonstrated that water imbibitions caused by capillary pressure and gravity segregation can play important roles in water-saturation distribution and redistribution, particularly during extended shut-in, which in turn affects gas flow significantly. Moreover, an unfavorable combination of relative permeability, capillary pressure, stress-sensitive fracture conductivities, and invasion-zone permeability damage can lead to water-blockage problems.
Analysis of Gasfloods Using Semilog Graphs of Free-Gas Gas/Oil Ratio vs. Cumulative Oil Production
Authors: Warner H.R. , McGregor D.S. , Laieb K. , Morsli H.
Published: June 2014

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Abstract

This work describes the use of semilog graphs of the free-gas gas/oil ratio (GOR) vs. cumulative oil production to analyze the performance of fields with large-scale gasflood operations. After gas breakthrough, and if field operations are reasonably constant, linear trends are found on these graphs and these trends can be extrapolated to project future oil recovery. This technique is similar to the use of semilog graphs of water/oil ratio (WOR) vs. cumulative oil production to analyze waterflood performance.

The conceptual and theoretical bases for this approach are described, along with assumptions required to develop this technique from basic flow equations. Analysis of miscible-gasflood historical data from the Hassi Messaoud (HMD) (Algeria) and University Block 31 (west Texas, USA) oil fields is presented by use of this technique. As was the case with waterflood analysis using log-WOR-vs.-cumulative-oil-production graphs, for gasflood analysis this technique is shown to apply somewhat more generally than the theory might suggest. This technique is shown to be applicable at the individual-production-well level, pattern level, or for a reservoir as a whole.

Introduction

For the past 60 years, a technique used to analyze waterflood performance has been to prepare semilog graphs of the producing WOR vs. cumulative oil production. These graphs have been used because, in most cases, a linear trend is observed from which future production performance can be projected. The purpose of this paper is to discuss the application of a similar technique to fields in which there have been long-term, large-scale gasflooding operations.

The process of gas displacing oil is similar to that of water displacing viscous oil, given that the viscosity ratio is approximately the same. There are differences, and those will be discussed. The primary difference is that in most oil fields, the oil contains considerable dissolved gas, which must be taken into account when analyzing gasflood performance. Other differences are considered that generally appear either to be insignificant or to counteract each other.
Methods of Making Fine-Dispersed Gas-Water Mixtures (DWGM) and Calculation Parameters Dispersion Device to Obtain DWGM With Optimum Data
Authors: Dmitriy Kuravskiy
Published: June 2014

Increased oil production from the reservoir is one of the most important tasks of the Russian oil and gas industry. There are many ways to solve this problem; however, in connection with tightening standards on the disposal of associated gas (PNG), there is a need to develop technologies that simultaneously can provide two objectives: 1) to dispose of PNG, and, 2) to affect the reservoir, increasing recovery efficiency. Injection of a homogeneous mixture consisting of water and associated gas is used as one of the effective ways of solving this problem. Gas is induced into the flow of water by a dispersion device in order to create DWGM, such fine-dispersed water-gas mixtures are used as a reservoir displacement agent. Application of DWGM avoids the major shortcomings of traditional water and gas flooding. DWGM serves to improve sweep efficiency as opposed to the result of single phase gas breakthrough from layers with high permeability.

The effective use of DWGM depends on several different factors. The most important factors are degree of dispersion and the percentage of gas in DWGM. The main goals of this work are the comparison of different methods of generating DWGA, their primary characteristics, and the calculation parameters of dispersal devices required for DWGM with optimal parameters.

Research of oil-displacement by DWGM was carried out on a two- and three-phase coreflood set up at the Scientific Center of Thermodynamics and Physics of Formation, OOO "VNIIGAZ". The multiphase coreflooding set up was developed by Temco, Inc. (Tulsa, OK, USA) and was assembled by Terra Tek, Inc..
Procedure for Elimination of Gas-cone by Using Salt Crystals (Case Study)
Authors: Megyery M. , Koncz I. , Szittar A. , Tiszai Gy.
Published: June 2014

A part of the reservoirs within Hungary have got a big gas cap and a thin oil-bearing zone. During production from their vertically as well as horizontally drilled oil bearing intervals, it is typical that the rate of oil production is decreased by the gas-coning.

Our procedure reduces the effect of gas-coning by injecting sodium chloride saturated brine into the gas-coning oil wells. When the quantity of the solvent (water) and/or the solubility of the salt is diminished, salt crystals will precipitate in the part of pores of the reservoir. (In the German-language literature the denomination of the effect is Salzzementation) Gas-coning eliminations consist of several alternate injections of salt saturated brine, oil and ethanol slugs. After treatment, the mobile phases (gas, oil) influence salt crystals differently. It was experienced the gas is not able to dissolve the salt crystals, because it has no mobile water. Gas transports salt crystals into the pore throats, thus the „permeability barrier" in the gas flow zone remains. However, oil contains some water to dissolve the salt crystals. In the oil flow zone, the „permeability barrier" ceases gradually, and the former permeability is restored.

15 oil wells (2 horizontal ones among them) were treated for eliminating gas-coning. For surplus oil calculations, production forecasts were prepared. Surplus oil was calculated as the difference between actual and forecast production data. 67% of the treatments gave a positive result. From 1999 till the end of 2008 the project resulted in 113 000 m3 surplus oil. Taking into account all of the treated wells, the economic result was six times larger than the input cost at least.

As both horizontal wells have given good results, the procedure can be recommended for such wells especially if the reservoir is significantly heterogeneous.
How Significant Is the P90 Value as a Measure of the Reserves' Downside?
Authors: Gupta S.. , Gupta R.. , van Elk J.F.. F. , Vijayan K..
Published: June 2014

Probabilistic methods for reserves estimation, including uncertainty quantification and probabilistic aggregation, have gained widespread acceptance in the oil and gas industry, since the first comprehensive guidelines were issued by the Society of Petroleum Engineers (SPE) (Swinkels 2001). The probabilistic methods now used in the oil industry, as proposed in these guidelines, are similar to those also used in portfolio theory and risk management by the finance industry. A significant amount can be learned from the extensive experience with probabilistic methods and quantification of risk with measures like value-at-risk (VAR), in financial risk management. Especially, the guidelines issued by the Basel II Accord (Bank for International Settlements 2006) and the discussions since the 2008 financial crisis contain important lessons.

In this paper, we examine a fundamental question: "Is the P90 reserves value an appropriate measure for quantifying the reserves’ downside?" For the P90 reserves value to be considered a good measure of the reserves’ downside, it needs to possess a number of basic characteristics involving P90 reserves for each field and the probabilistically aggregated P90 reserves for the portfolio of fields. Analogous to the definition of a coherent risk measure used in the finance industry, we define these characteristics for P90 reserves.

The P90 reserves are as good a risk measure as VAR used in the financial industry. However, like VAR, it is not a coherent risk measure. A possible uncertainty scenario, in which one of these necessary characteristics does not hold, is given. An alternative measure of risk for quantifying the reserves’ downside, defined as the average reserves over the confidence interval higher than P90, is presented. This is a coherent risk measure.

In this paper, we highlight the appropriateness and limitations of using the P90 reserves estimate as a measure of the reserves’ downside. Understanding of the limitations posed by using the P90 reserves value is vital in management of reserves risk.
Simplified Forecasting of Tight/Shale-Gas Production in Linear Flow
Authors: Nobakht Morteza , Mattar Louis , Moghadam Samane , Anderson David Mark
Published: June 2014

This paper presents a simplified method of production forecasting for tight/shale-gas reservoirs exhibiting extended periods of linear flow, without the use of complex tools (e.g., analytical models or numerical models). The method, which is applicable to hydraulically fractured vertical wells and multifractured horizontal wells, is simple because it relies principally on a plot of inverse rate vs. square root of time, and it is rigorous in that it is based on the theory of linear flow and combines the transient linear-flow period with hyperbolic decline during boundary-dominated flow.

The dominant flow regime observed in most tight/shale-gas wells is linear flow, which may continue for several years. This linear flow will be followed by boundary-dominated flow at later times. Therefore, the method proposed in this study is applicable for forecasting production data for these wells because it considers these two important flow regimes. The derivation is presented for a hydraulically fractured well, and this simplified method can be applied both to hydraulically fractured vertical wells and to horizontal wells with multiple fractures. The application of this method to multifractured horizontal wells in the Marcellus and Barnett shale gas is also presented.

The method is validated by comparing its results with test cases, which are built using numerical simulation for hydraulically fractured vertical wells. For each case, only the first year of the synthetic production data is then used for the analysis. It is found that there is reasonable agreement between the forecast rates obtained using this method and the numerically simulated rates.

Currently, analysis techniques using material-balance time are being used in industry to analyze tight/shale-gas reservoirs. Because material-balance time is actually boundary-dominated flow superposition time, these analyses may show symptoms of boundary-dominated flow even though the reservoir is still in transient flow. The advantages of the forecasting method proposed in this study are that: (1) it is not biased toward any flow regimes because no superposition time functions are used; (2) reliable forecasts can be obtained without using pseudotime--this is an advantage because using pseudotime introduces complexities and an iterative procedure; and (3) the only major unknown is the drainage area.
Application of Optimizing Techniques for Studying Field Producing Operations
Authors: Attra H.D. , Wise W.B. , Black W.M.
Published: June 2014

The purpose of this paper is to illustrate a comparatively new approach for solving a problem that has plagued oil producers for many years-how to make the most money with available field production capacity.

In a very basic operation such as a top-allowable one-well field, a computer and staff of engineers are not required to determine that the best operation is to produce that well at its maximum for as long a time as it will produce. However, as, the problem becomes more complex and the number of wells and number of reservoirs increase, it probably will be a wise choice to devote some engineering thought and calculation time to determine the best way to operate that field on both an ultimate and day-to-day basis.

Continued developments in the field broadly referred to as "operations research" have led to a number of useful engineering analyses for optimizing field operational problems. One of these techniques, termed linear programing, is particularly interesting because of its potential applications to the study of complex oilfield operating problems. Linear programing is concerned with the problem of planning a complex set of interdependent activities in the best possible (optimal) fashion.

A field application of linear programing is being used to maximize daily income from a multi-reservoir producing operation. The initial results of this study indicate that the linear programing techniquecan be applied effectively to field problems,can be used to detect unsuspected avenues for improving operations andcan effect a significantly improved means of controlling field operations through the use of the high-speed computer.