bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Oil Recovery by Low-Salinity Waterflooding
Authors: Morrow Norman , Buckley Jill
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.

Waterflooding was first practiced for pressure maintenance after primary depletion and has since become the most widely adopted improved-oil-recovery (IOR) technique. It is now commonly applied at the outset of reservoir development. The reservoir-connate-water composition usually differs significantly from the composition of water available for injection. Parametric laboratory studies of crude-oil recovery showed that, for connate and injected brines of the same or different composition, waterflood recoveries could differ substantially depending on brine composition. However, laboratory tests designed to predict waterflood performance usually have not incorporated the difference in connate and injected brines.

Low-Salinity Waterflooding

Improved recovery of crude oil by low-salinity waterflooding (LSW), with only modest increase in resistance to flow, was reported by Tang and Morrow (1997). Since then, many laboratories and organizations have grappled with the opportunities and problems associated with identifying, reproducing, and explaining the low-salinity effect (LSE). Various forms of LSE and the necessary conditions for its occurrence are reviewed. The evidence, mounting rapidly from both field and laboratory studies, is examined with the aim of facilitating identification of LSW targets and design of the floods.

Necessary conditions for LSE identified by Tang and Morrow (1999) in Berea-sandstone cores were as follows.

• Significant clay fraction

• Presence of connate water

• Exposure to crude oil to create mixed-wet conditions

Note, however, that while necessary for the types of sandstones investigated, these conditions are not sufficient; many outcrop sandstones meeting these conditions have not shown LSE recovery. The cause of such significant differences has yet to be identified. Identification of promising LSE projects requires specific laboratory tests, followed by pilot tests of increasing scale. It should be noted also that some special cases of LSE have been identified in which dissolution of soluble minerals occurs upon injection of the low-salinity flood water in either carbonates or sandstones.
Comparative PVT Simulation: An Application to Australasian Fluid Samples
Authors: O'Reilly D. I.
Published: June 2014

This paper investigates the effectiveness of Equations of State (EOS) when used to simulate Pressure-Volume-Temperature (PVT) experiments. The phase behaviour and volumetrics of six EOS and three EOS modifications (9 models in total) has been examined using a newly developed package inside the MATLAB software. The simulator is an expandable system designed to compare different EOS and fluid characterisation schemes. Comparison will be made between the Soave-Redlich-Kwong (SRK), Peng-Robinson (PR), Adachi-Lu (AL), Patel-Teja (PT), Schmidt-Wenzel (SW) and Esmaeilzadeh-Roshanfekr (ER) EOS, for which the SRK, PR and ER equations optionally include published volumetric shift parameters. Local Australasian fluid samples are studied to illustrate strengths and weaknesses of different EOS, using several fluid types. It was found that the Esmaeilzadeh-Roshanfekr EOS is most accurate for predicting gas-condensate properties, while the original SRK and PR equations remain reliable for oil samples.

The purpose of the study is twofold: (1) Increasingly companies are optimising experimental PVT studies by simulating subsequent experiments using EOS1,2, or they are using preliminary simulation to evaluate the need for further experiments. This is particularly true for multi-contact miscibility experiments such as the Rising Bubble Apparatus or slim-tube test, which are time-consuming and costly. Furthermore, (2) there is reason to believe that thermodynamic models which provide better representation of PVT experiments without matching will perform best after complete matching has occurred. Matching EOS simulation with experiment, known as tuning or regression, is used in industry before application in compositional simulation. Obviously, this is only possible if PVT studies are available.
Flow of Emulsions in Porous Media
Authors: Romero Mao Ilich
Published: June 2014

Flow of emulsion in porous media plays an important role in many enhanced oil recovery processes. Drops may partially block pore passages leading to a better sweep of the reservoir. Despite all the efforts, the detailed mechanism of how emulsions flow through the pore space is not completely understood. Modeling the flow of emulsion in porous media is extremely challenging. In many situations the size of the dispersed phase drops is in the same order of magnitude of the pore throats. Therefore, in the pore scale the emulsion cannot be described as a single phase liquid with an effective viscosity.

In this work we analyze the flow of emulsion in porous media by experiments and a capillary network model. The model is based on the flow rate-pressure drop relation of emulsion flow through constricted capillaries, which is a function of the capillary number of the flow, liquid properties and the ratio of drop to capillary throat diameter. The capillary network modeling was constructed in order to obtain macroscopic parameters from microscopic flow behavior.

The results show how the permeability changes with Darcy velocity. At low flow rates, the large drops partially block the smallest pores, leading to a low permeability. At high flow rates, the pressure gradient in each capillary is strong enough to force the drops to flow through the constrictions. Consequently, the permeability rises with capillary number. The results agree well to experimental measurements in sandstone cores.
Asphaltene Deposition and Its Effects on Production Performances In the Development of Oil Field by CO2 Flooding: A Numerical Simulation Assessment
Authors: Ju Binshan , Qiu Xiaofeng , Qin Jishun , Chen Xinglong , Fan Tailiang
Published: June 2014

Injection of CO2 into oil reservoirs is a smart operation for the fact that it is not only to enhance oil recovery (EOR), but also to reduce carbon dioxide emission as it is one of greenhouse gases. However, either in a CO2 miscible or in a CO2 immiscible displacement process, the injected CO2 into the oil formation can induce flocculation and deposition of asphaltene. This can cause numerous production problems with a detrimental effect on the permeability and oil production. Moreover, wettability of oil reservoir rock may change for asphaltene adsorption on pore surfaces due to the polarity of asphaltene. Based on the understanding the behavior of this organic matter under reservoir conditions, a mathematical model considering asphaltene precipitation and wettability alteration is presented and an oil field scaled numerical simulator is developed to predict for asphaltene precipitation problems during CO2 flooding. The simulation results show that the porosity and permeability in the area swept by CO2 and the vicinity of injection well bore decrease for asphaltene precipitation, pressure gradients become larger than numerical results ignoring asphaltene precipitation. Before CO2 breakthrough at production wells, the performance of production wells has not been affected obviously by asphaltene deposition. However, after CO2 breakthrough at production wells, the formation damage occurs in the vicinity of production well bore and leads to decrease dramatically in permeability and production rate.
A Fast and Efficient Numerical-Simulation Method for Supersonic Gas Processing
Authors: Dengyu Jiang , Eriqitai Eriqitai , Wang Changliang , Tang Lin
Published: June 2014

Supersonic-swirling-separation technology is an innovative gasconditioning technology that separates heavy hydrocarbon and water vapor from natural gas. The Laval nozzle, where the condensation occurs, is used to generate supersonic flow and achieve a high degree of supersaturation in this natural-gas dehydration unit. Therefore, the nozzle shape has a strong impact on the nonequilibrium phase transition and plays a decisive role in distribution of nucleation and growth rate. To optimize the structure of the Laval nozzle and achieve higher separation efficiency, numerical simulation plays an important role in accelerating development cycles and cutting down the cost of experiment.

To avoid the complexity of using the multiphase model and real-gas model, a quick and efficienct method is validated and used to determine the location of the nucleation zone and the droplet-growth zone in this paper.

On the basis of the Fluent software, this paper presents a numerical-simulation method for condensing flow using user-defined function (UDF). This method itself is an extension of Fluent software for simulating condensing flow by adding a condensation model. The corrected internally-consistent-classical-theory (ICCT) model and Gyarmathy model (gya82) are employed to prescribe this phase transition. Actually, this problem is solved by coupling the Navier-Stokes (N-S) equation and condensate mass equation.

Condensing flow in a Laval nozzle is simulated at different nozzle-pressure ratios (NPRs) and initial supersaturations. The results show that high cooling rate results in a high value of supersaturation and nucleation rate in a supersonic expansion Laval-nozzle flow. When condensation occurs, the flow is affected by the latent heat released and the total temperature is increased. This method can accurately predict the distribution of the condensing flow parameters, find an optimized flow state to obtain larger droplets, and ensure that the latent heat released is moderate to maintain a steady flow. Finally, this method is applied to the numerical simulation of a full-scale supersonic-swirling-separator flow field under different work conditions.
Prevention of Formation Damage Induced by Mud Lost in Deep Fractured Tight Gas Reservoir in Western Sichuan Basin
Authors: Kang Yili , You Lijun , Xu Xinghua , Liao Zhonghui
Published: June 2014

Western Sichuan deep tight gas reservoirs are characterized by ultralow permeability, natural fractures, partial ultralow water saturation, and a hard brittle shale interlayer. The matrix permeability varies from 0.001 to 0.1 md. The natural-fracture width varies from several micrometers to 3.0 mm, but it could be up to 5.0 mm during well operations. Lost circulation--inducing severe reservoir damage and increasing nonproductive time--has frequently occurred during well drilling and cementation during the past 10 years. The traditional lost-circulation-control techniques such as physical, chemical, or physicochemical methods, which used to permanently choke the lost-circulation passage of the nonpay zone, are not suitable for the pay zone. Several technologies, including air underbalanced-drilling fluids, noninvasive drilling fluids, and traditional temporary-shielding-fluids (TSF) technology, were tried to prevent formation damage owing to lost circulation but none of them worked well. Air underbalanced drilling has to be given up because of formation-water influx and wellbore instability. Noninvasive drilling fluids are ineffective because of the low percentage of return permeability and low bearing strength of the mudcake in the fractured formation. Traditional TSF technology is applicable for the damage prevention only in reservoirs with fractures less than 100 um in width. Temporary-sealing-loss (TSL) fluids with millimeter-sized agents take advantage of acid-soluble bridging particles to rapidly form a tight plugging zone near the wellbore that efficiently seals the pore throats and fractures. TSL fluids were developed to prevent formation damage in leaky fractured reservoirs. With the application of the new TSL fluids, Well W2, in the second member of the Xujiahe formation, obtained a gas-production rate of 52.16×104 m3/d. Furthermore, lost circulation never occurred during drilling of Well W101.
Integrated Permeability Analysis in Tight and Brecciated Carbonate Reservoir
Authors: Mohammadlou M. H. , Mørk M. B. , Langeland H.
Published: June 2014

Permeability provides an indication of the ability of a porous medium to transmit fluid and is significant in evaluating reservoir productivity. A case study which compares different methods of permeability prediction in a complex carbonate reservoir is presented in this paper. Presence of siliciclastic fines and diagenetic minerals (e.g. dolomitization) within carbonate breccias has resulted in a tight and heterogeneous carbonate reservoir in this case.

The first part of this paper covers permeability estimation from independent methods. This part includes conventional core analysis (CCAL), mercury injection capillary pressure tests (MICP), modular formation dynamic tester (MDT), and nuclear magnetic resonance log (NMR). Having different permeability predictors of several methods may be helpful in the permeability calculation, but the deviation of the results from one to the other is often inevitable. Due to discrepancy between the methods it is difficult to select reliable permeability values in the reservoir characterization.

In general, the NMR log provides a continuous permeability prediction compared to the other. In the second part of the paper it is attempted to use all the data to calibrate the NMR derived permeability in a realistic behavior. Initially both the Schlumberger Doll Research (SDR) and free-fluid (Timur-Coates) permeability models are employed in this work. The tight and brecciated parts of the rock, wettability effect of the pore surfaces, and residual oil within the flushed zone increase the uncertainty and discrepancy of the NMR estimated permeabilities compared to the other models. A new modified Timur-Coates model was established based on fluid saturations and isolated pore volume of the rock. This model yields a reasonable correlation with core derived permeabilities from CCAL and MICP. However, due to the reservoir heterogeneity particularly in the brecciated parts, a discrepancy of the results between the core data and the created model is not avoidable.
Reservoir to Surface: An Effective Combination to Unlock Oil Reserves From Aging Reservoirs
Authors: Moreno J. , Kartoatmodjo G. , Friedel T. , Zulkhifly F. , Tan L.
Published: June 2014

One of the main drivers of field development is maximization of oil reserves. The value of assets and therefore companies is strongly linked to the amount of producible reserves of their holdings. Traditionally the full potential of the reservoir is locked due to a series of limitations both at the sub-surface and surface. Increasing in oil demand challenges the development not only to improve on oil recovery but also boost the near term production.

Subsurface models are extensively used to determine the optimum development strategy for the field, infill wells are used to target un-swept areas of the reservoir, while water and or gas injection may be used to preserve reservoir energy. In comparison surface facilities are not so extensively looked after especially in an offshore environment, and often times only a de-bottlenecking of the optimum sub-surface case is performed. The integration between surface network modeling and subsurface modeling is critical to ensure field operation is in line with reservoir management and the facility is adequate to handle the expected production.

This paper discusses the various stages of optimization, using numerical simulation combined with a surface model, to determine the impact of surface operations in overall field performance. The results allowed shifting of the resources to further understand the surface operations which affect the overall field performance as well as identifying near term production enhancement opportunity. This work shows how an effective combination of reservoir energy preservation by means of upgrading the current surface facilities and adding optimized existing wells accounts for as much as 50% of the total potential recoverable reserves.

Furthermore, after evaluating each development options, a matrix risk is formulated to take into account not only the quality and quantity of the data but also the degree of man interventions during the life of the field (surface optimization). Value-of-information figures were then associated to each of the suggested new data/equipment to help prioritize the development As a result measurement efforts were carried out including horizontal production logs to minimize uncertainty of the reservoir contribution.
Next Generation Technologies for Underbalanced Coil Tubing Drilling
Authors: Kozlov Anton , Frantzen Serve , Gorges Thomas , Al Khamees Shaker , Guzman Julio C. , Aduba Anthony A , da Silva Thiago P.
Published: June 2014

Technology improvements are continuing to expand the capability of coiled tubing directional drilling (CTDD) worldwide. Increased CTDD activity in advanced underbalanced re-entry applications that require precise wellbore (multilateral) placement and real-time monitoring of downhole parameters has led to the development of bottom-hole drilling assemblies (BHAs) with enhanced functionality.

Saudi Aramco identified CTDD as an important technology for redeveloping its gas reserves and is dedicated to expanding the technical limit of CTDD application. Saudi Aramco successfully completed its first underbalanced re-entry coiled tubing drilling (UBCTD) pilot project and is now progressing to consolidate this technology in subsequent UBCTD operations. A great impetus has now been placed on further improving UBCTD project economics through improved operational efficiency and the introduction of new underbalanced coiled tubing drilling techniques and services.

This paper provides an overview of the new Rib Steered Motor (RSM) technology and its potential benefits to UBCTD. It details recent worldwide deployments of the rib steering motor technology focusing on operations in the Kingdom of Saudi Arabia which provide the perfect testing ground when geosteering with RSM. Future advances using UBCTD geosteering technology rely on a close working relationship between the field operator and the service company. Successful application of UBCTD applys to a wide range of mature oil and gas fields for enhancing access to the producing reservoir to drive the economic extraction of additional reserves.
The Effect of Restricted Fluid Entry on Well Productivity
Authors: Brons F. , Marting V.E.
Published: June 2014

Introduction

In the past, other authors have studied the influence of a skin effect on the productivity of a well. This skin effect, expressed by the skin factor S, is considered to be caused by a thin layer of impaired permeability immediately around the wellbore and extending vertically over the whole productive interval penetrated by the well. The skin factor S is defined as follows.

Based on this, the impairment in productivity caused by a skin can be expressed by the fractional loss in productivity I, which is the loss in productivity divided by the total unimpaired productivity.

Statement of Problem

The present paper deals with a different kind of productivity impairment. Consider a well in which part of the productive formation is blocked off completely, either by incomplete penetration or by exclusion of parts of the productive zone by blank casing. In Fig. 1 (A, B and C), three examples are shown. Fig. 1(A) shows the situation where a well only partially penetrates the formation. This often is done to combat the actual or imagined danger of bottom-water coning. Fig. 1(B) shows a well producing from only the central portion of a productive interval. This type of completion is sometimes used where both water and gas coning are a problem. Although the case of a well producing through perforated casing cannot be treated in a manner similar to the previous two cases (where radial flow in the horizontal plane is assumed), Fig. 1(C) shows several intervals open to production and qualitatively describes this case (as will be discussed later).
Feasibility Study of Applying Steamflooding in a Reservoir with High Shale/Sand: Teca Field
Authors: Trigos E. M. , Gonzales A. R. , Pinilla J. M. , Munoz S. M. , Mercado D. P.
Published: June 2014

Colombia is a country with important reserves of heavy oil, located mainly at the "llanos orientales" and at the "Magdalena Valley Medium" basin, the oilfields located in this basin, have been developed using cyclic steam stimulation, showing recovery factors close to 15%, indicating that a large quantity of oil has not been removed yet.

Due to the above reasons, it has been thought in the steam flooding as an alternative for the extraction of remaining oil, but the intercalated shale in the deposits in question, acting as thieves, heat affects the thermal efficiency of the process, why is not clear whether the steam flooding will be viable in the deposits of the Magdalena valley, specifically in the TECA field. Given the above, it is necessary to conduct a study to determine the effect of the intercalated shale on thermal efficiency. This study was carried out using numerical simulation and analytical models in the case of a numerical simulation model was compared with intercalations of shale and a homogeneous model, we conducted a further analysis of sensitivity to the rock and fluid properties, as well as operational parameters for the implementation of a steam flooding, including a scheme of selective injection.

Finally, we found that the thermal efficiency is greatly affected by the intercalated shale is decreasing by up to 30%, a value considerably higher than would seriously affect the technical and economic feasibility of the project but has been observed to implement a scheme of selective injection could increase the efficiency of the process, making this more feasible to perform.
Optimizing Well Productivity and Maximizing Recovery from a Mature Gas Field: The Application of Wellhead Compressor Technology
Authors: Sumaryanto _ , Lukman Ade , Kontha I Nyoman , Turnbull Bill
Published: June 2014

VICO Indonesia is an Oil and Gas company which has operated the Sanga-Sanga Production Sharing Contract (PSC) in East Kalimantan, Indonesia, since 1968. More than 750 development wells have been drilled to date in the harsh swampy environment of the Mahakam Delta in East Kalimantan. Today, the mature reservoirs are predominantly gas, extremely depleted, and have an average recovery factor of 70%.

The flowing tubing head pressure (FTHP) for wells in these developments are typically 50 to 60 psi, allowing for a potential reservoir abandonment pressure of approximately 300 psi. The reservoirs are depletion drive gas reservoirs. Through the installation of wellhead compression, further lowering the FTHP, a lower abandonment pressure was obtained and consequently reserves recovery increased through well life extension.

In 2008, VICO installed 19 wellhead compressors, achieving FTHP’s as low as 5 psi. This resulted in increased productivity, individual well production stability and an expected improvement in overall recovery volumes from the reservoirs. The compressors installed have a small footprint (3.4 × 8.5 m), low fuel consumption and minimal operating costs. Each unit has a nominal capacity of 1 MMscfd. Through the careful well selection process and the ability to quickly relocate the compressors to different wells has enabled Vico to maximize the benefit of this technology.

The paper will present the benefits of wellhead compression in mature gas fields, the selection process for the wells and the compressors, and the operational challenges faced by the project.
Using the SPE/WPC/AAPG/SPEE/SEG PRMS To Evaluate Unconventional Resources
Authors: Chan Phillip , Etherington John R. , Aguilera Roberto
Published: June 2014

It is the intention of the SPE/World Petroleum Council (WPC)/ American Association of Petroleum Geologists (AAPG)/ Society of Petroleum Evaluation Engineers (SPEE)/ Society of Exploration Geophysicists (SEG) Petroleum Resources Management System (PRMS) to provide a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework. The reserves and resources definitions and application guidelines are designed to be applicable to both conventional and unconventional petroleum accumulations, regardless of their in-place characteristics, the extraction method applied, or the degree of processing required to yield a marketable product.

The fact that unconventional resources are usually pervasive throughout a large area and are not significantly affected by hydrodynamic influences may require different approaches in evaluation. Assessments may include an increased sampling density to define uncertainty of in-place volumes and the variations in quality of reservoir and of hydrocarbons and their detailed spatial distribution for the design of specialized extraction methods.

This paper summarizes the special problems in the estimation and evaluation of shale gas. However, similar procedures can be used for other unconventional resources. The material is largely drawn from the recently published SPE Application Guidelines to the PRMS, supplemented with illustrations from actual field examples.

The rapidly advancing exploitation of unconventional resources has opened up many development opportunities, especially in North America. Shale gas and bitumen have already caused major impact on energy supply. We anticipate these opportunities will expand rapidly throughout the world. Achieving a better understanding of the special problems in unconventional-resources evaluation will help us build on PRMS to develop a more consistent approach to classification and categorization, accounting for unique project risks and uncertainties.
The PEARL Initiative: Producing, Sharing and Managing blended On line, Mobile and Instructor Led Learning Content within the Oil Industry
Authors: Cardinali Fabrizio
Published: June 2014

This paper is authored by Fabrizio Cardinali, board member of the European Learning Industry Group and the IMS Global Learning Consortium and CEO of Giunti Labs, a leading provider of Mobile and Learning Content Management and Digital Repository Solutions, (www.giuntilabs.com) in collaboration with the Petroleum Training Alliance, PetroSkills (www.petroskills.com), and with one of its leading oilfield services company members, Baker Hughes (www.bakerhughes.com).

This paper introduces the need to better compete in the contemporary Petroleum Labor provisioning and Skills training sector; analyzing solutions to better produce, assemble, distribute and share open knowledge resources across open and interoperable networks while personalizing them for different skill gaps, personal media and location of use.

This paper introduces the need for a commonly referenced Petroleum Engineering Abstract Reference framework for producing, managing, sharing and distributing standard & blended Learning materials. It defines present and future learning scenarios and services in an abstract way, starting with the proposal of common standards and protocols (Application Profile) for the sharing and reuse of standard learning, reference and knowledge materials within and across the oil vertical together with their best implementation practices and showcase implementations.
Quantitative Formation Evaluation in High Angle and Horizontal Wells Using LWD Measurements: Field Application of Integrated Log Modeling Workflows
Authors: Mendoza Alberto , Gaillot Philippe , Mardon Duncan , Zhou Jinjuan , Guo Pingjun , Wertanen Scott , Yin Hezhu
Published: June 2014

Quantitative petrophysical evaluation in high-angle and horizontal (HA/HZ) wells has remained elusive primarily because of the presence of complex log responses and lack of appropriate modeling capabilities. Recent advances in numerical simulation of nuclear and resisitivity logs in HA/HZ wells have significantly improved interpretation of log responses in complex borehole-formation geometries. Additionally, developments in fast simulation methods have enabled application of log response modeling in conjunction with field measurements. Although a full understanding of nuclear and resistivity logs response in HA/HZ wells is yet to be resolved, application of advanced interpretation techniques to field measurements yields more reliable petrophysical analyses.

In this paper, we implement processing methods that more effectively combine short- and long-spaced density measurements together with forward modeling of azimuthal nuclear and scalar resisistivity logging-while-drilling (LWD) logs to construct a common subsurface model. This log response-coherent model constructed from field measurements is then used for conventional petrophysical analysis. To demonstrate our workflow, we analyze four horizontal wells penetrating sand-silt sequences in the Chayvo field (northeast coast of Sakhalin Island, Russia) with apparent dip angles ranging between 80 and 90 degrees. The wells were drilled with oil-base mud (OBM) and include standard LWD triple-combo logs.

Field-based log response-coherent models of resistivity, density, and neutron measurements are used to estimate lithology volumetrics, porosity, and water saturation. Results from depth coherence processing and forward modeling show improved resolution and estimation of formation layer petrophysical properties which yield more accurate estimates of reserves in place compared to those initially estimated from field logs. Additionally, the average properties in high- and low-net intervals from the HA/HZ wells are compared to properties estimated in near offset vertical wells, which include core samples.
Exploration of Non-Common Petroleum Targets
Authors: Koblov E. G. , Tkacheva N. A. , Kharakhinov A. V.
Published: June 2014

The problem of oil and gas content of the fractured reservoirs in the North Sakhalin has appeared at the beginning of the thirties years on the morrow of opening the natural oil shows in the Pogranichny downthrown block in argillo-siliceous deposits of the Pilengsky suite. The intensive degree of these displays (only in the area of Pogranichny settlement, there were discovered above 100 natural shows of mainly oil by means of the subsequent works), and the significant range of their spread permitted even then to make a proposal about the second (the lower-miocene) oil-and-gas bearing series in the section of the North Sakhalin.

The industrial oil content of this series (according to the present-day concepts, it is related to the upper oligocene) was established in 1971 by opening of the petroleum deposit in the fissured silicite of the Pilengsky suite at Okruzhnoye field.
Experimental Characterization of Production Behaviour Accompanying the Hydrate Reformation in Methane-Hydrate-Bearing Sediments
Authors: Ahn Taewoong , Park Changhyup , Lee Jaehyoung , Kang Joo M. , Nguyen Hieu T.
Published: June 2014

This paper experimentally analyzes the production characteristics of hot-brine stimulation accompanying hydrate reformation in the presence of methane hydrate. Many attempts have been made to recover methane hydrate commercially, such as depressurization, thermal stimulation, and inhibitor injection. Hot-brine injection coupled with thermal recovery with inhibitor injection has been investigated as an efficient production scheme, but the hydrate reformation during the dissociation is problematic, and it negatively influences the recovery rate.

An experimental apparatus divided the sediment sample into 12 blocks not only to describe 1D dissociation effectively but also to control the temperature accurately. The specified amount of methane hydrate was formed artificially in unconsolidated and packed sediments where the average particle size, absolute permeability, and porosity were 260 µm, 4.4 darcies, and 42%, respectively. The production trends were observed in the temperature range of approximately 283.85 - 303.15 K and with injection rates of 10 and 15 cm3/min. Methane hydrate reformed in all the tests; the reason for this may be the recombination of water and the dissociated methane in the downstream zones. In the early time, the production rate was low, but it increased significantly in later time. The former was why most of gas that dissociated in the upstream zones was consumed to reform hydrate in the downstream areas, while the latter came from the dissociation of initial and reformed hydrate. The dissociation front moved fast at the higher temperature and injection rate. The production efficiency of the test at 15 cm3/min and 294.55 K was similar to that of the test at 10 cm3/min and 303.15 K. The results confirmed the production behaviour of methane hydrate under the reformation phenomenon and could provide the fundamentals to develop an efficient production scheme based on hot-brine stimulation.
Bacterial Survival in Fractured Shale-Gas Wells of the Horn River Basin
Authors: Moore Sherry L. , Cripps Colin M.
Published: June 2014

Traditional ideology on the upper temperature limits of life suggest that extreme temperatures such as those observed in the Horn River Basin shale-gas formation (i.e., up to 175°C) should alleviate microbiologically influenced corrosion and souring concerns associated with hydraulic-fracturing procedures. The present case history investigates the accuracy of this theory. Horn River basin wells currently in the flowback or production stage and the source water used to fracture these wells were studied for the presence and identity of viable bacteria. The effectiveness of two biocides (one glutaraldehyde-based and the other cocodiamine-based) in eradicating these bacteria in both the field and the laboratory was also studied. The results show that source ponds are highly contaminated with bacteria. Furthermore, the high-temperature, high-pressure downhole conditions in this region are not sufficient for eradicating bacteria introduced during the fracturing process. These bacteria survive and establish viable, proliferating communities. Biocide, applied continuously "on the fly" during fracturing, was effective at mitigating the downhole bacteria concern. Laboratory studies further showed that more-established bacterial communities were much more resistant to biocidal treatment. Therefore, early mitigation strategies will likely be key in the prevention of microbiologically induced corrosion and souring.
Natural-Gas Potential in the St. Lawrence Lowlands of Quebec:A Case Study
Authors: Lavoie Jean Yves , Marcil Jean Sebastien , Dorrins Peter , Lavoie Jeremie , Aguilera Roberto
Published: June 2014

Since the announcement made in April 2008 concerning the shale-gas potential of the southern Québec lowlands, 30 new wells have been drilled in the area. The calcareous and organic-rich Middle Ordovician Utica shale is the main target of this recent exploration effort. Current knowledge of the area's geology has led operators to subdivide the shale-gas potential into different play types. To date, most operations have been performed in approximately one-third of the shale basin in the medium-to-deep thermogenic shale-gas play (1000 to 2000 m), located in the central part of the Saint Lawrence lowlands. With original-gas-in-place (OGIP) estimates ranging from 120 to 160 Bcf per section, the deep play is considered to be promising. Current efforts focus on determining the highest gas-prone unit within the Utica. The remaining two-thirds of the shale basin has not been largely tested yet, but the potential remains promising.

On the basis of exploration work carried out over the past 5 years in southern Québec, four other play types have been described: (1) shallow-to-medium-depth thermogenic shale gas, (2) overthrusted shale gas, (3) biogenic shale gas, and (4) Intra-Appalachians subbasin shale gas. They are less explored than the deep-shale play, but also present interesting potential.

This paper describes the previously mentioned plays using basin geology, shale mineralogy, organic-matter type, gas geochemistry, structural style, and infrastructure access. The characteristics of the previously described plays are reviewed from geological, geochemical, structural, and production perspectives. Results of evaluations using the concept of flow units, and volumes of OGIP calculated by various organizations, are compared with a recent evaluation using the petroleum resources management system (PRMS).

It is concluded that there is promising hydrocarbon potential in the Saint Lawrence lowlands of Québec that continues to stimulate operators to pursue the exploration and development of these plays.
An Analytical Model To Predict Cumulative Steam/Oil Ratio (CSOR) in Thermal-Recovery SAGD Process
Authors: Miura Kohei , Wang Jin
Published: June 2014

This paper presents a simple yet sophisticated analytical model to predict cumulative steam/oil ratio (CSOR) using material/energy balance and gravity-drainage theory in which CSOR is a function of average reservoir properties (porosity, permeability, heat capacity, and thermal conductivity) and time-dependent variables (injection temperature, rising chamber height, chamber oil saturation, and produced-fluid temperature) to mimic practical steam-assisted gravity-drainage (SAGD) processes. This model has been applied to predict CSORs of typical wells in the JACOS Hangingstone SAGD project. History-match results show the reliability and accuracy of the model at different geological conditions. The analytical model has proved to be satisfactory in predicting CSOR by reasonably adjusting a limited number of reservoir parameters, such as formation permeability, effective net pay, and operational parameters.
Effect of Initial Water Saturation on the Thermal Efficiency of the Steam-Assisted Gravity-Drainage Process
Authors: Oskouei S. Javad P. , Maini Brij B. , Moore R. Gordon , Mehta Sudarshan A.
Published: June 2014

The commercial viability of the steam-assisted gravity-drainage (SAGD) process is affected negatively by several undesirable reservoir features, such as pronounced heterogeneity, low vertical permeability, thick and areally extensive shale barriers, and steam thief zones. The efficiency of SAGD projects is also affected by the presence of higher water saturation in the target zone. Although the presence of small mobile-water saturation is not considered harmful, reservoirs with high water saturation may be poorly suited for the SAGD process. Nonetheless, SAGD remains the only practical technology for in-situ extraction of oil from oil-sand reservoirs, even when mobile water is present. This raises the question of how much mobile water is prohibitive.

To investigate the effect of water saturation on SAGD performance, high-pressure physical-model experiments were carried out. Different levels of water saturations were established in the model by modifying the packing and saturating techniques. SAGD experiments were carried out by injecting superheated steam at controlled rates and producing the oil from the production well at constant pressure. The injection rate was selected to keep the pressure difference between the injector and the producer at a low level.

The oil-production behavior was analyzed to evaluate the effect of water saturation on the thermal efficiency of the process. On the basis of the results of low- (immobile) and high- (mobile) water-saturation experiments, it was observed that the oil-recovery factor dropped by 6.6% when the initial water saturation was increased from 14.7% to 31.8%.
Permeability Prediction Based on Capillary Model
Authors: Susilo Agus
Published: June 2014

Determining the correlation between permeability and porosity is very crucial in reservoir characterization and description. Generally, the correlation is utilized to predict a permeability value from porosity data which results from logging or coring for uncored zones. Difficulty in building a general correlation between permeability and porosity became the developmental background of the hydraulic conductivity method. This method lies on the classification of the permeability and porosity relationship, based on pore size and geometry.

The purpose of this study is to generate grouping of rock samples based on zonation of permeability and porosity correlation with characteristics of pore structure and geometry. The capillary pipe model is the basis for developing the method. This method can be used to determine permeability in positions only having porosity data from the log. This paper also presents a method to determine the value of effective hydraulic pore diameter dH, by employing the Gauss-Newton method.

This study has used 145 core samples originated from multi-stacked sandstone reservoirs. The core samples have very wide ranges of porosity (0.042 – 0.46) and permeability (0.1 – 7442 mD). Analysis of both the data and the correlation generates new understanding about pore structure and geometry. Application of the developed method to all the core samples results in very good permeability prediction.

Keyword: Hydraulic Conductivity, dH, Gauss-Newton.
A Mathematical Analysis of the Mechanism of Ultrasonic Induced Fluid Percolation in Porous Media: Part I
Authors: Najafi I.
Published: June 2014

This work concerns with experimentally and analytically investigation of free gravity drainage process in porous media under the influence of ultrasonic wave radiation. Glass beads ranges from 70 to 100 mesh sizes were packed and used in the tests. The working fluids consist of distilled water, kerosene and Doroud and Paidar crude oils as wetting and air as non-wetting phase. The measured oil recovery data along with Hagoort (1984) backward methodology were used to determine and to compare the relative permeability of wetting phases in presence and absence of ultrasonic radiation. In addition the relative permeability of non-wetting phases for both cases were calculated from inverse modeling of provided data. The results showed that wave enhanced the relative permeability of phases, except than for the case of Paidar crude oil, which is asphaltenic and the oil recovery decreased by sonication. The momentum conservation equation, as well as Darcy's and Stokes’ laws were combined and a new model for predicting absolute permeability of porous media radiated by ultrasonic waves is developed. The surprising result of developed model is that the permeability of porous medium is independent to the wave parameters. Investigating the influence of ultrasonic wave radiation on viscosity of the fluids and capillary pressure, showed that the radiation acts in opposition to capillary pressure effect, meaning while there is a period of radiation time at which the oil viscosity is decreasing, and after which it is increasing. Finally, the obtained flow parametrers under the influence of wave radiation applied in conventional model of gravity drainage. Well mached observed between predictions of model modified by this method and measured recovery data confirmed the applicability of flow parameters modification method for predicting the gravity drainage behavior under the influence of ultrasonic wave.
Effect of Various Injected Gases on Methane Recovery and Water Production in Enhanced Coalbed Methane Operations
Authors: Jamshidi Marjan
Published: June 2014

Methane production from coalbed methane (CBM) fields started as a method for keeping coal mining safe from explosions. Major CBM fields are located in San Juan, Powder River, Forest City, Black Worrier and Illinois. Majority of the US natural gas production comes from coalbed methane formations. These formations also have the potential of carbon dioxide (CO2) storage through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of gases such as CO2, nitrogen (N2) or a mixture of both gases has been proven to recover additional natural gas resources.

Most of the coalbed methane formations contain large amounts of water or can be in communication with an aquifer. As a result a large amount of water is often co-produced during the natural gas extraction. The water being produced from deep formations is not high purity water and contains nitrate, nitrite, and chlorides and has high level of total dissolved solids.

Production of methane from CBM is facilitated by the reduction of the methane partial pressure in the coal seam by either pumping the formation water to the surface or by injecting a dissimilar gas. The produced water contains a lot of harmful impurities which should be removed. Therefore, disposal of the produced water is an environmental challenge and accordingly, a reduction of the produced water is enviable.

In this paper we present a detailed numerical investigation of the potential reduction in water production during ECBM operations while increasing the methane production. We employ a three-dimensional coalbed model with an aquifer located on the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength, cleat spacing and sorption characteristics of the coal. The amount of gas/water that is produced varies extensively depending on the aquifer strength. We demonstrate that injection of CO2 and/or N2 in some settings reduces the water handling problem substantially.

CBM is an essential energy source with a lot of formations being exceptional candidates for ECBM recovery processes. The analysis we present in this paper on the water production reduction by using the injection gas which relatively produces less water provides new strategy for future operations.
Study of the PVT Behavior of Methane and Ester-Based Drilling Fluid Mixtures
Authors: Kim N. R.
Published: June 2014

Brazilian oil and gas reserves are primarily located in offshore fields, in deep and ultradeep water depths, where well construction is specially complex. Continuous development of drilling technology leads to the increasing application of synthetic-based drilling fluids, which have adequate characteristics such as lubricity, shale inhibition and low toxicity. In offshore conditions a gas kick is of major concern, as formation gas will dissolve in the organic compound of the synthetic-based drilling fluid. The better understanding of gas solubility is very important in operational and environmental safety of well control procedures, to avoid a blowout situation. In the present work methane was chosen because it is the principal component of natural gas, while ester was used in the formulation of drilling fluids. Knowledge of phase equilibrium of these mixtures, at high pressures and high temperatures, demands experimental tests, which are specific, expensive and time consuming. This work presents experimental data, obtained from PVT analysis of methane and ester-based emulsion mixtures. Laboratory tests were performed with last generation equipment, where a complete visualization of the sample fluid was possible. The mixture was loaded into a PVT cell and the equilibrium was reached at the pressure and temperature conditions expected at bottomhole. At constant temperature, the volume in the cell was monitored as a function of the pressure. An original gas enrichment experimental procedure was devised in order to cover the temperature, pressure and methane concentration range with a long term, single liquid amount test. Measured data enabled the estimation of the bubble pressure, solubility, density and formation volume factor of the mixtures, developing new correlations for pressures up to 15,000 psi and temperatures up to 266 °F. A thermodynamic modeling based on Peng-Robinson equation of state was applied to predict the experimental bubble point. The present work enlarges the limited thermodynamic properties database about methane – ester systems that is available in the literature and furnish scientific answers to the well control problems encountered when drilling with ester based emulsions.