bluuebunny/crossref_metadata_2025_split 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

Abstract
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

Abstract
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

Abstract
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

Summary
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

Summary
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

Abstract
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

Abstract
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

AbstractTechnology 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

Abstract
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

Abstract
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.