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Most Cited Petroleum Articles

The most cited articles published since 2014, extracted from Scopus.

Status of surfactant EOR technology

Volume 1, Issue 2, June 2015, Pages 97-105
James J. Sheng

© 2015 Southwest Petroleum University Surfactant enhanced oil recovery (EOR) includes surfactant flooding and surfactant stimulation. The main functions of surfactants are to reduce interfacial tension and wettability alteration. This paper is to review the EOR technology related to surfactant injection. The reviewed topics include the following: • Surfactant EOR mechanisms • Factors affecting interfacial tension • Trapping number • Screening criteria • Laboratory work • Numerical simulation work • Summary of pilot and large-scale applications • Surfactants used • Salinity gradient • Surfactant EOR in carbonate reservoirs • Surfactant EOR in shale reservoirs

A comprehensive review on proppant technologies

Volume 2, Issue 1, March 2016, Pages 26-39
Feng Liang | Mohammed Sayed | Ghaithan A. Al-Muntasheri | Frank F. Chang | Leiming Li

© 2015 Southwest Petroleum University The main function of traditional proppants is to provide and maintain conductive fractures during well production where proppants should meet closure stress requirement and show resistance to diagenesis under downhole conditions. Many different proppants have been developed in the oil & gas industry, with various types, sizes, shapes, and applications. While most proppants are simply made of silica or ceramics, advanced proppants like ultra-lightweight proppant is also desirable since it reduces proppant settling and requires low viscosity fluids to transport. Additionally, multifunctional proppants may be used as a crude way to detect hydraulic fracture geometry or as matrices to slowly release downhole chemical additives, besides their basic function of maintaining conductive hydraulic fractures. Different from the conventional approach where proppant is pumped downhole in frac fluids, a revolutionary way to generate in-situ spherical proppants has been reported recently. This paper presents a comprehensive review of over 100 papers published in the past several decades on the subject. The objectives of this review study are to provide an overview of current proppant technologies, including different types, compositions, and shapes of proppants, new technologies to pump and organize proppants downhole such as channel fracturing, and also in-situ proppant generation. Finally, the paper sheds light on the current challenges and emphasizes needs for new proppant development for unconventional resources.

A review on hydraulic fracturing of unconventional reservoir

Volume 1, Issue 1, March 2015, Pages 8-15
Quanshu Li | Huilin Xing | Jianjun Liu | Xiangchon Liu

© 2015 Southwest Petroleum University Hydraulic fracturing is widely accepted and applied to improve the gas recovery in unconventional reservoirs. Unconventional reservoirs to be addressed here are with very low permeability, complicated geological settings and in-situ stress field etc. All of these make the hydraulic fracturing process a challenging task. In order to effectively and economically recover gas from such reservoirs, the initiation and propagation of hydraulic fracturing in the heterogeneous fractured/porous media under such complicated conditions should be mastered. In this paper, some issues related to hydraulic fracturing have been reviewed, including the experimental study, field study and numerical simulation. Finally the existing problems that need to be solved on the subject of hydraulic fracturing have been proposed.

Determination of oil well production performance using artificial neural network (ANN) linked to the particle swarm optimization (PSO) tool

Volume 1, Issue 2, June 2015, Pages 118-132
Mohammad Ali Ahmadi | Reza Soleimani | Moonyong Lee | Tomoaki Kashiwao | Alireza Bahadori

© 2015 Southwest Petroleum University Greater complexity is involved in the transient pressure analysis of horizontal oil wells in contrast to vertical wells, as the horizontal wells are considered entirely horizontal and parallel with the top and underneath boundaries of the oil reserve. Therefore, there is an essential need to estimate productivity of horizontal wells accurately to examine the effectiveness of a horizontal well in terms of technical and economic prospects. In this work, novel and rigorous methods based on two different types of intelligent approaches including the artificial neural network (ANN) linked to the particle swarm optimization (PSO) tool are developed to precisely forecast the productivity of horizontal wells under pseudo-steady-state conditions. It was found that there is very good match between the modeling output and the real data taken from the literature, so that a very low average absolute error percentage is attained (e.g., <0.82%). The developed techniques can be also incorporated in the numerical reservoir simulation packages for the purpose of accuracy improvement as well as better parametric sensitivity analysis.

CO2utilization: Developments in conversion processes

Volume 3, Issue 1, March 2017, Pages 109-126
Erdogan Alper | Ozge Yuksel Orhan

© 2017 Southwest Petroleum University Carbon dioxide capture, utilization and storage (CCUS) –including conversion to valuable chemicals-is a challenging contemporary issue having multi-facets. The prospect to utilize carbon dioxide (CO2) as a feedstock for synthetic applications in chemical and fuel industries -through carboxylation and reduction reactions-is the subject of this review. Current statute of the heterogeneously catalyzed hydrogenation, as well as the photocatalytic and electrocatalytic activations of conversion of CO2to value-added chemicals is overviewed. Envisaging CO2as a viable alternative to natural gas and oil as carbon resource for the chemical supply chain, three stages of development; namely, (i) existing mature technologies (such as urea production), (ii) emerging technologies (such as formic acid or other single carbon (C1) chemicals manufacture) and (iii) innovative explorations (such as electrocatalytic ethylene production) have been identified and highlighted. A unique aspect of this review is the exploitations of reactions of CO2–which stems from existing petrochemical plants-with the commodity petrochemicals (such as, methanol, ethylene and ethylene oxide) produced at the same or nearby complex in order to obtain value-added products while contributing also to CO2fixation simultaneously. Exemplifying worldwide ethylene oxide facilities, it is recognized that they produce about 3 million tons of CO2annually. Such a CO2resource, which is already separated in pure form as a requirement of the process, should best be converted to a value-added chemical there avoiding current practice of discharging to the atmosphere. The potential utilization of CO2, captured at power plants, should also been taken into consideration for sustainability. This CO2source, which is potentially a raw material for the chemical industry, will be available at sufficient quality and at gigantic quantity upon realization of on-going tangible capture projects. Products resulting from carboxylation reactions are obvious conversions. In addition, provided that enough supply of energy from non-fossil resources, such as solar [1], is ensured, CO2reduction reactions can produce several valuable commodity chemicals including multi-carbon compounds, such as ethylene and acrylic acid, in addition to C1 chemicals and polymers. Presently, there are only few developing technologies which can find industrial applications. Therefore, there is a need for concerted research in order to assess the viability of these promising exploratory technologies rationally.

Application of nanotechnology for enhancing oil recovery – A review

Volume 2, Issue 4, December 2016, Pages 324-333
Chegenizadeh Negin | Saeedi Ali | Quan Xie

© 2016 Southwest Petroleum University Nanotechnology has attracted a great attention in enhancing oil recovery (EOR) due to the cost-effective and environmental friendly manner. The size of nanoparticles for EOR usually is in a range of 1–100 nm, which may slightly differ from various international organisations. Nanoparticles exhibit significantly different properties compared to the same fine or bulk molecules because of much higher concentration of atoms at their surface as a result of ultra-small size. In particular, one of the most useful and fascinating properties of these particles is to creating a massive diffusion driving force due to the large surface area, especially at high temperatures. Previous studies have shown that nanoparticles can enhance oil recovery by shifting reservoir wettability towards more water-wet and reducing interfacial tension, yet this area is still open for discussion. It is worth noting that the potential of nanoparticles to reduce the oil viscosity, increase the mobility ratio, and to alter the reservoir permeability has not been investigated to date. Depending on the operational conditions of the EOR process, some nanoparticles perform more effectively than others, thus leading to different levels of enhanced recovery. In this study, we aim to provide a summary on each of the popular and available nanoparticles in the market and list their optimum operational conditions. We classified nanoparticles into the three categories of metal oxide, organic and inorganic particles in this article.

Most common surfactants employed in chemical enhanced oil recovery

Volume 3, Issue 2, June 2017, Pages 197-211
Chegenizadeh Negin | Saeedi Ali | Quan Xie

© 2017 Southwest Petroleum University Chemical enhanced oil recovery (EOR) and particularly surfactant injection has recently received a great deal of attention. The suggested recovery mechanisms after injecting surfactants include wettability alteration and IFT reduction. If a surfactant is properly selected according to the environmental variables-such as pressure, temperature, salinity, it can lead to more efficient enhanced recovery from an oil reservoir. On the other hand, poor selection of the surfactant can result in a low recovery and can even become detrimental to the reservoir due to undesirable wettability alteration and possible rock dissolution resulting in a chemical reaction with displacing fluid and blockage of the pore space. Also, choosing the wrong surfactant without considering the rock mineralogy may result in high adsorption on the pore surface of the rock and unnecessary waste of resources. It is also worthy to note that surfactants are some of the most expensive chemicals used during EOR. Extensive literature review suggests that anionic surfactant are the preferred surfactant category for EOR especially when it comes to sandstone reservoirs. Occasionally, in specific situations a better performance have been reported after injecting cationic, non-ionic or mixtures of both surfactants, particularly when dealing with carbonate reservoirs. This paper presents in detail a review of the most commonly applied surfactants in EOR studies and the optimum application criteria for of each type. To the best of the authors’ knowledge, such detailed and comprehensive review is not available in the literature, presently.

Why are brittleness and fracability not equivalent in designing hydraulic fracturing in tight shale gas reservoirs

Volume 2, Issue 1, March 2016, Pages 1-19
Mao Bai

© 2016 Southwest Petroleum University With respect to brittleness, it is about the type of material and its related strength. In comparison with ductile material under load, brittle material has a relatively shorter plastic deformation and responds dominantly by the elastic deformation. With respect to fracability, it is about the rock failure under the ultimate rock strength in either brittle or ductile formation. In comparison, the higher fracable formation should have smaller formation strength than that of the lower fracable formation. In consequence, it is not certain that the brittle formation is easy to fracture than the ductile formation since brittle formation may have greater strength than ductile formation even though the exceptions may exist. More complications arise when evaluating the responses of subsurface formation in great depth to the formation types (e.g. brittle formation or ductile formation). Under this condition, the impact of confinement on the fracability cannot be ignored. In general, the formation subject to higher confinement pressure is more difficult to fracture as the formation strength is greater. Conversely, the formation subject to lower confinement pressure is easy to fracture since the formation strength is smaller. In view of efficient stimulation of tight shale gas reservoirs, it is unclear whether we would choose the brittle interval or the ductile interval to fracture as the strength of either interval is unknown. However, it is apparent that we should choose the formation interval with a higher fracability which is equivalent to the lower formation strength. Under the similar confinements, the lower formation strength may be indicated by the smaller unconfined compressive strength (UCS). As a result, it is advisable that the most fracable interval is the one with lowest UCS. When evaluating the present technology, the formation brittleness should no longer be the associated subject matter as we are unclear about its role to improve the fracability of the tight formation. Disassociating the brittleness with the fracability enables us to focus on identifying the true mechanisms of efficient fracturing of tight shale gas reservoirs. With the objective review and sensible definition of brittleness used in the present petro-physical field to identify the desirable fracturing intervals, the paper presents the ambiguities of using the brittleness to define the formation fracability and points out that the formation brittleness can be unrelated to the formation fracability. As an alternative approach, the paper provides an effective method to define the most fracable formation intervals in designing the hydraulic fracturing in tight shale gas formations.

Solid amine sorbents for CO2capture by chemical adsorption: A review

Volume 3, Issue 1, March 2017, Pages 37-50
Elif Erdal Ünveren | Bahar Özmen Monkul | Şerife Sarıoğlan | Nesrin Karademir | Erdoğan Alper

© 2017 Southwest Petroleum University Amines are well-known for their reversible reactions with CO2, which make them ideal for CO2capture from several gas streams, including flue gas. In this respect, selective CO2absorption by aqueous alkanolamines is the most mature technology but the process is energy intensive and has also corrosion problems. Both disadvantages can be diminished to a certain extent by chemical adsorption of CO2selectively. The most important element of the chemical adsorption of CO2involves the design and development of a suitable adsorbent which consist of a porous support onto which an amine is attached or immobilized. Such an adsorbent is often called as solid amine sorbent. This review covers solid amine-based studies which are developed and published in recent years. First, the review examines several different types of porous support materials, namely, three mesoporous silica (MCM-41, SBA-15 and KIT-6) and two polymeric supports (PMMA and PS) for CO2adsorption. Emphasis is given to the synthesis, modifications and characterizations -such as BET and PXRD data-of them. Amination of these supports to obtain a solid amine sorbent through impregnation or grafting is reviewed comparatively. Focus is given to the adsorption mechanisms, material characteristics, and synthesis methods which are discussed in detail. Significant amount of original data are also presented which makes this review unique. Finally, relevant CO2adsorption (or equilibrium) capacity data, and cyclic adsorption/desorption performance and stability of important classes of solid amine sorbents are critically reviewed. These include severa PEI or TEPA impregnated adsorbents and APTES-grafted systems.

A predictive model of chemical flooding for enhanced oil recovery purposes: Application of least square support vector machine

Volume 2, Issue 2, June 2016, Pages 177-182
Mohammad Ali Ahmadi | Maysam Pournik

© 2015 Southwest Petroleum University Applying chemical flooding in petroleum reservoirs turns into interesting subject of the recent researches. Developing strategies of the aforementioned method are more robust and precise when they consider both economical point of views (net present value (NPV)) and technical point of views (recovery factor (RF)). In the present study huge attempts are made to propose predictive model for specifying efficiency of chemical flooding in oil reservoirs. To gain this goal, the new type of support vector machine method which evolved by Suykens and Vandewalle was employed. Also, high precise chemical flooding data banks reported in previous works were employed to test and validate the proposed vector machine model. According to the mean square error (MSE), correlation coefficient and average absolute relative deviation, the suggested LSSVM model has acceptable reliability; integrity and robustness. Thus, the proposed intelligent based model can be considered as an alternative model to monitor the efficiency of chemical flooding in oil reservoir when the required experimental data are not available or accessible.

Prediction of reservoir brine properties using radial basis function (RBF) neural network

Volume 1, Issue 4, December 2015, Pages 349-357
Afshin Tatar | Saeid Naseri | Nick Sirach | Moonyong Lee | Alireza Bahadori

© 2015 Southwest Petroleum University Aquifers, which play a prominent role as an effective tool to recover hydrocarbon from reservoirs, assist the production of hydrocarbon in various ways. In so-called water flooding methods, the pressure of the reservoir is intensified by the injection of water into the formation, increasing the capacity of the reservoir to allow for more hydrocarbon extraction. Some studies have indicated that oil recovery can be increased by modifying the salinity of the injected brine in water flooding methods. Furthermore, various characteristics of brines are required for different calculations used within the petroleum industry. Consequently, it is of great significance to acquire the exact information about PVT properties of brine extracted from reservoirs. The properties of brine that are of great importance are density, enthalpy, and vapor pressure. In this study, radial basis function neural networks assisted with genetic algorithm were utilized to predict the mentioned properties. The root mean squared error of 0.270810, 0.455726, and 1.264687 were obtained for reservoir brine density, enthalpy, and vapor pressure, respectively. The predicted values obtained by the proposed models were in great agreement with experimental values. In addition, a comparison between the proposed model in this study and a previously proposed model revealed the superiority of the proposed GA-RBF model.

Characterization of the pore system in an over-mature marine shale reservoir: A case study of a successful shale gas well in Southern Sichuan Basin, China

Volume 1, Issue 3, September 2015, Pages 173-186
Yang Yang | Kunyu Wu | Kunyu Wu | Tingshan Zhang | Mei Xue

© 2015 Southwest Petroleum University During the past two years the shale gas exploration in Southern Sichuan basin received some exciting achievements. Data of a new appraisal well showed that the gas producrtions of vertical well and horizontal well are ∼1.5 × 104m3/day/well (with maximum ∼3.5 × 104m3/day/well) and ∼12.5 × 104m3/day/well (with maximum ∼40 × 104m3/day/well), respectively, indicating a good gas potential in this area. Eight core samples from the reservoir were investigated by using a carbon sulfur analyzer, microphotometry, x-ray diffractometry, field-emission scanning electron microscopy (FE-SEM), mercury injection porosimetry (MIP), and low-pressure nitrogen adsorption to obtain a better understanding of the reservoir characteristics of the Upper Ordovician–Lower Silurian organic-rich shale. Results show that the total organic carbon (TOC) content ranges from 0.5% to 5.9%, whereas the equivalent vitrinite reflectance (VRr) is between 2.8% and 3.0%. Pores in the studied samples were observed in three modes of occurrence, namely, interparticle pores, intraparticle pores, and intraparticle organic pores. The total porosity (P) ranges from 1.6% to 5.3%, and MIP data sets suggest that pores with throats larger than 20 nm contribute little to the pore volume. Low-pressure N2adsorption isotherms indicate that the total specific surface area (SBET) ranges from 9.6 m2/g to 18.9 m2/g, and the pore volume (V) ranges from 0.011 cm3/g to 0.020 cm3/g. The plot of dV/dW versus W shows that the fine mesopores (pore size(BJH)< 4 nm) mainly contribute to the pore volume. The P, SBET, and V show a good positive correlation with TOC and a weak positive correlation with the total clay mineral content, thus indicating that the nanopores are mainly generated by the decomposition of organic matter. The reservoir characteristics of the Upper Ordovician–Lower Silurian organic-rich shale are comparable with commercial shale gas plays in North America. The sample gas contents with TOC >2% are more than 3.0 m3/ton. The observation can be a good reference for the future exploration and evaluation of reservoir in this area.

Shale characteristics impact on Nuclear Magnetic Resonance (NMR) fluid typing methods and correlations

Volume 2, Issue 2, June 2016, Pages 138-147
Mohamed Mehana | Ilham El-monier

© 2016 Southwest Petroleum University The development of shale reservoirs has brought a paradigm shift in the worldwide energy equation. This entails developing robust techniques to properly evaluate and unlock the potential of those reservoirs. The application of Nuclear Magnetic Resonance techniques in fluid typing and properties estimation is well-developed in conventional reservoirs. However, Shale reservoirs characteristics like pore size, organic matter, clay content, wettability, adsorption, and mineralogy would limit the applicability of the used interpretation methods and correlation. Some of these limitations include the inapplicability of the controlling equations that were derived assuming fast relaxation regime, the overlap of different fluids peaks and the lack of robust correlation to estimate fluid properties in shale. This study presents a state-of-the-art review of the main contributions presented on fluid typing methods and correlations in both experimental and theoretical side. The study involves Dual Tw, Dual Te, and doping agent's application, T1-T2, D-T2and T2secvs. T1/T2methods. In addition, fluid properties estimation such as density, viscosity and the gas-oil ratio is discussed. This study investigates the applicability of these methods along with a study of the current fluid properties correlations and their limitations. Moreover, it recommends the appropriate method and correlation which are capable of tackling shale heterogeneity.

A review of crosslinked fracturing fluids prepared with produced water

Volume 2, Issue 4, December 2016, Pages 313-323
Leiming Li | Ghaithan A. Al-Muntasheri | Feng Liang

© 2016 Southwest Petroleum University The rapidly increasing implementations of oilfield technologies such as horizontal wells and multistage hydraulic fracturing, particularly in unconventional formations, have expanded the need for fresh water in many oilfield locations. In the meantime, it is costly for services companies and operators to properly dispose large volumes of produced water, generated annually at about 21 billion barrels in the United States alone. The high operating costs in obtaining fresh water and dealing with produced water have motivated scientists and engineers, especially in recent years, to use produced water in place of fresh water to formulate well treatment fluids. The objective of this brief review is to provide a summary of the up-to-date technologies of reusing oilfield produced water in preparations of a series of crosslinked fluids implemented mainly in hydraulic fracturing operations. The crosslinked fluids formulated with produced water include borate- and metal-crosslinked guar and derivatized guar fluids, as well as other types of crosslinked fluid systems such as crosslinked synthetic polymer fluids and crosslinked derivatized cellulose fluids. The borate-crosslinked guar fluids have been successfully formulated with produced water and used in oilfield operations with bottomhole temperatures up to about 250 °F. The produced water sources involved showed total dissolved solids (TDS) up to about 115,000 mg/L and hardness up to about 11,000 mg/L. The metal-crosslinked guar fluids prepared with produced water were successfully used in wells at bottomhole temperatures up to about 250 °F, with produced water TDS up to about 300,000 mg/L and hardness up to about 44,000 mg/L. The Zr-crosslinked carboxymethyl hydroxypropyl guar (CMHPG) fluids have been successfully made with produced water and implemented in operations with bottomhole temperatures at about 250+ °F, with produced water TDS up to about 280,000 mg/L and hardness up to about 91,000 mg/L. In most of the cases investigated, the produced water involved was either untreated, or the treatments were minimum such as simple filtration without significantly changing the concentrations of monovalent and divalent ions in the water. Due to the compositional similarity (high salinity and hardness) between produced water and seawater, crosslinked fluids formulated with seawater for offshore and onshore jobs were also included. The crosslinked guar and derivatized guar fluids have been successfully formulated with seawater for operations at bottomhole temperatures up to about 300 °F. Operating costs have been significantly reduced when produced water or seawater is used to formulate fracturing fluids in place of fresh water. With various challenges and limitations still existing, the paper emphasizes the needs for new developments and further expansion of produced water reuse in oilfield operations.

Emergence of nanotechnology in the oil and gas industry: Emphasis on the application of silica nanoparticles

Volume 3, Issue 4, December 2017, Pages 391-405
Muili Feyisitan Fakoya | Subhash Nandlal Shah

© 2017 Southwest Petroleum University The application of nanotechnology in the oil and gas industry is on the rise as evidenced by the number of researches undertaken in the past few years. The quest to develop more game-changing technologies that can address the challenges currently facing the industry has spurred this growth. Several nanoparticles, of different sizes and at different concentrations, have been used in many investigations. In this work, the scope of the study covered the application of nanotechnology in drilling and hydraulic fracturing fluids, oilwell cementing, enhanced oil recovery (which includes transport study, and foam and emulsion stability), corrosion inhibition, logging operations, formation fines control during production, heavy oil viscosity reduction, hydrocarbon detection, methane release from gas hydrates, and drag reduction in porous media. The observed challenges associated with the use of nanoparticles are their stability in a liquid medium and transportability in reservoir rocks. The addition of viscosifier was implemented by researchers to ensure stability, and also, surface-treated nanoparticles have been used to facilitate stability and transportability. For the purpose of achieving better performance or new application, studies on synergistic effects are suggested for investigation in future nanotechnology research. The resulting technology from the synergistic studies may reinforce the current and future nanotechnology applications in the oil and gas industry, especially for high pressure and high temperature (HPHT) applications. To date, majority of the oil and gas industry nanotechnology publications are reports of laboratory experimental work; therefore, more field trials are recommended for further advancement of nanotechnology in this industry. Usually, nanoparticles are expensive; so, it will be cost beneficial to use the lowest nanoparticles concentration possible while still achieving an acceptable level of a desired performance. Hence, optimization studies are also recommended for examination in future nanotechnology research.

Advancement and new perspectives of using formulated reactive amine blends for post-combustion carbon dioxide (CO2) capture technologies

Volume 3, Issue 1, March 2017, Pages 10-36
Chikezie Nwaoha | Chikezie Nwaoha | Teeradet Supap | Raphael Idem | Raphael Idem | Chintana Saiwan | Chintana Saiwan | Paitoon Tontiwachwuthikul | Paitoon Tontiwachwuthikul | Paitoon Tontiwachwuthikul | Mohammed J. AL-Marri | Abdelbaki Benamor

© 2016 Southwest Petroleum University Chemical absorption using amine–based solvents have proven to be the most studied, as well as the most reliable and efficient technology for capturing carbon dioxide (CO2) from exhaust gas streams and synthesis gas in all combustion and industrial processes. The application of single amine–based solvents especially the very reactive monoethanolamine (MEA) is associated with a parasitic energy demand for solvent regeneration. Since regeneration energy accounts for up to three–quarters of the plant operating cost, efforts in its reduction have prompted the idea of using blended amine solvents. This review paper highlights the success achieved in blending amine solvents and the recent and future technologies aimed at increasing the overall volumetric mass transfer coefficient, absorption rate, cyclic capacity and greatly minimizing both degradation and the energy for solvent regeneration. The importance of amine biodegradability (BOD) and low ecotoxicity as well as low amine volatility is also highlighted. Costs and energy penalty indices that influences the capital and operating costs of CO2capture process was also highlighted. A new experimental method for simultaneously estimating amine cost, degradation rate, regeneration energy and reclaiming energy is also proposed in this review paper.

Investigation of alkaline–crude oil reaction

Volume 1, Issue 1, March 2015, Pages 31-39
James J. Sheng

© 2015 Southwest Petroleum University One of the mechanisms of alkaline flooding relies on alkaline reaction with organic acids (saponifiable components) in the crude oil to produce an in situ surfactant called soap that lowers interfacial tensions. However, this mechanism is not quantified in the literature. For example, what is the fraction of acid components which react with alkaline solution to generate soap? How much soap can be generated? In this paper, this mechanism and related issues are discussed, analyzed or quantified. In particular, the numerical simulation approach is used. The results show that only a fraction of acid components can be converted into soap; the amount of generated soap could be low. A minimum pH (e.g. 9) is needed for the acids to be converted to soap. The literature information on the effect of amount of acid components (total acid number) on oil recovery is also discussed.

Strengthening shale wellbore with silica nanoparticles drilling fluid

Volume 2, Issue 2, June 2016, Pages 189-195
Yili Kang | Jiping She | Hao Zhang | Lijun You | Minggu Song

© 2016 Southwest Petroleum University Nanoparticles have been widely used to reduce wellbore instability problems of shale formation. In this paper, nanoparticle-containing water-based drilling fluids (WBDFs) and oil-based drilling fluids (OBDFs) were evaluated by running three new tests including spontaneous imbibition, swelling rate and acoustic transit time. Results showed that, for the WBDFs, nanoparticles leaded to higher plastic viscosity (PV) and yield point (YP), and lower API-filtration. Moreover, because pore throats of shale can be plugged by nanoparticles, imbibition amount, swelling rate, and Young's-modulus reduction of shale decreased significantly. Higher concentration of nanoparticles can induce better plugging effect. However, for the OBDFs, nanoparticles did not show these positive effects like the nano WBDFs, even leaded to some negative effects such as higher filtration and larger Young's-modulus reduction. The main reasons are that the silica nanoparticles can easily disperse in the WBDFs, and effectively prevent the filtrate invading into shale by plugging pore throats. But the same silica nanoparticles are difficult to disperse in OBDFs, and do not perform the expected functions. This study indicates that nano WBDFs have great potential to reduce the wellbore instability problems of shale formation.

A novel imidazoline derivative as corrosion inhibitor for P110 carbon steel in hydrochloric acid environment

Volume 1, Issue 3, September 2015, Pages 237-243
Lei Zhang | Lei Zhang | Lei Zhang | Yi He | Yanqiu Zhou | Yanqiu Zhou | Ranran Yang | Ranran Yang | Qiangbin Yang | Qiangbin Yang | Dayong Qing | Dayong Qing | Qianhe Niu | Qianhe Niu

© 2015 Southwest Petroleum University A novel imidazoline derivative, 2-methyl-4-phenyl-1-tosyl-4, 5-dihydro-1H-imidazole (IMI), was prepared and investigated as corrosion inhibitor for P110 carbon steel in 1.0 M HCl solution by weight loss measurements, potentiodynamic polarization and electrochemical impedance spectroscopy (EIS) tests. The inhibition efficiency increased with the rising concentration of IMI inhibitor. The test results and fitting data indicated that the IMI behaved as a mixed-type inhibitor and obeys the Langmuir adsorption isotherm. Scanning electron microscopy (SEM) was carried out to investigate the surface of carbon steel specimens, showing great protection from aggressive solution. Finally, inhibition mechanism of IMI on metal surface was further discussed.

Study on temperature distribution along wellbore of fracturing horizontal wells in oil reservoir

Volume 1, Issue 4, December 2015, Pages 358-365
Junjun Cai | Yonggang Duan

© 2015 Southwest Petroleum University The application of distributed temperature sensors (DTS) to monitor producing zones of horizontal well through a real-time measurement of a temperature profile is becoming increasingly popular. Those parameters, such as flow rate along wellbore, well completion method, skin factor, are potentially related to the information from DTS. Based on mass-, momentum-, and energy-balance equations, this paper established a coupled model to study on temperature distribution along wellbore of fracturing horizontal wells by considering skin factor in order to predict wellbore temperature distribution and analyze the factors influencing the wellbore temperature profile. The models presented in this paper account for heat convective, fluid expansion, heat conduction, and viscous dissipative heating. Arriving temperature and wellbore temperature curves are plotted by computer iterative calculation. The non-perforated and perforated sections show different temperature distribution along wellbore. Through the study on the sensitivity analysis of skin factor and flow rate, we come to the conclusion that the higher skin factor generates larger temperature increase near the wellbore, besides, temperature along wellbore is related to both skin factors and flow rate. Temperature response type curves show that the larger skin factor we set, the less temperature augmenter from toe to heel could be. In addition, larger flow rate may generate higher wellbore temperature.

Experimental and simulation determination of minimum miscibility pressure for a Bakken tight oil and different injection gases

Volume 3, Issue 1, March 2017, Pages 79-86
Sheng Li | Peng Luo

© 2017 Southwest Petroleum University The effective development of unconventional tight oil formations, such as Bakken, could include CO2enhanced oil recovery (EOR) technologies with associated benefits of capturing and storing large quantities of CO2. It is important to conduct the gas injection at miscible condition so as to reach maximum recovery efficiency. Therefore, determination of the minimum miscibility pressure (MMP) of reservoir live oil–injection gas system is critical in a miscible gas flooding project design. In this work, five candidate injection gases, namely CO2, CO2-enriched flue gas, natural gas, nitrogen, and CO2-enriched natural gas, were selected and their MMPs with a Bakken live oil were determined experimentally and numerically. At first, phase behaviour tests were conducted for the reconstituted Bakken live oil and the gases. CO2outperformed other gases in terms of viscosity reduction and oil swelling. Rising bubble apparatus (RBA) determined live oil–CO2MMP as 11.9 MPa and all other gases higher than 30 MPa. The measured phase behaviour data were used to build and tune an equation-of-state (EOS) model, which calculated the MMPs for different live oil-gas systems. The EOS-based calculations indicated that CO2had the lowest MMP with live oil among the five gases in the study. At last, the commonly-accepted Alston et al. equation was used to calculate live oil–pure CO2MMP and effect of impurities in the gas phase on MMP change. The Bakken oil–CO2had a calculated MMP of 10.3 MPa from the Alston equation, and sensitivity analysis showed that slight addition of volatile impurities, particularly N2, can increase MMP significantly.

Experimental study of Iranian heavy crude oil viscosity reduction by diluting with heptane, methanol, toluene, gas condensate and naphtha

Volume 2, Issue 4, December 2016, Pages 415-424
Amir Hossein Saeedi Dehaghani | Mohammad Hasan Badizad

© 2016 Southwest Petroleum University Due to the high viscosity of heavy crude oils, production from these reservoirs is a demanding task. To tackle this problem, reducing oil viscosity is a promising approach. There are various methods to reduce viscosity of heavy oil: heating, diluting, emulsification, and core annular flow. In this study, dilution approach was employed, using industrial solvents and gas condensate. The viscosity of two Iranian heavy crude oils was measured by mixing with solvents at different temperatures. Dilution of both oil samples with toluene and heptane, resulted in viscosity reduction. However, their effect became less significant at higher concentrations of diluent. Because of forming hydrogen bonds, adding methanol to heavy crude oil resulted in higher viscosity. By adding condensate, viscosity of each sample reduced. Gas condensate had a greater impact on heavier oil; however, at higher temperatures its effect was reduced. Diluting with naphtha decreased heavy oil viscosity in the same way as n-heptane and toluene. Besides experimental investigation, different viscosity models were evaluated for prediction of heavy oil/solvent viscosity. It was recognized that Lederer’ model is the best one.

Technical status and challenges of shale gas development in Sichuan Basin, China

Volume 1, Issue 1, March 2015, Pages 1-7
Pingli Liu | Yinsheng Feng | Liqiang Zhao | Nianyin Li | Zhifeng Luo

© 2015 Southwest Petroleum University During the past decade, shale gas developments have changed the energy structure in the US natural gas industry, and the exploration activities for shale gas are also increasing worldwide. According to the papers published in recent years, shale gas resources are quite abundant in China. With the successful experience obtained from North America, many state-of-the-art technologies are brought in and refined for field application. State-owned enterprise, private enterprises and foreign enterprises have all actively participated in the exploitation of shale gas. Compared with US, China faces many more challenges, both geological and above-ground, in the development of shale gas resources. This paper begins with the introduction of shale gas reserve distribution in China and the identified shale gas formation in Sichuan Basin. The following paper reviews the methodology employed in the geophysical prospecting, drilling and completion, and hydraulic fracturing process. Since China is in the early stage of shale gas development, there is a great technical gap between China and North America. Based on literature review, the major challenges faced in the exploration and production process are identified. What presented in this paper should be of particular interest to the personnels involved in shale gas production in China and countries that are about to set foot in shale gas business. It will also be of interest to researchers who are dedicated to developing these technologies to unlock unconventional gas resources in China.

Evolving simple-to-use method to determine water–oil relative permeability in petroleum reservoirs

Volume 2, Issue 1, March 2016, Pages 67-78
Mohammad Ali Ahmadi | Sohrab Zendehboudi | Maurice B. Dusseault | Ioannis Chatzis

© 2015 Southwest Petroleum University In the current research, a new approach constructed based on artificial intelligence concept is introduced to determine water/oil relative permeability at various conditions. To attain an effective tool, various artificial intelligence approaches such as artificial neural network (ANN), hybrid of genetic algorithm and particle swarm optimization (HGAPSO) are examined. Intrinsic potential of feed-forward artificial neural network (ANN) optimized by different optimization algorithms are composed to estimate water/oil relative permeability. The optimization methods such as genetic algorithm, particle swarm optimization and hybrid approach of them are implemented to obtain optimal connection weights involved in the developed smart technique. The constructed intelligent models are evaluated by utilizing extensive experimental data reported in open literature. Results obtained from the proposed intelligent tools were compared with the corresponding experimental relative permeability data. The average absolute deviation between the model predictions and the relevant experimental data was found to be less than 0.1% for hybrid genetic algorithm and particle swarm optimization technique. It is expected that implication of HGAPSO-ANN in relative permeability of water/oil estimation leads to more reliable water/oil relative permeability predictions, resulting in design of more comprehensive simulation and further plans for reservoir production and management.

CO2flooding strategy to enhance heavy oil recovery

Volume 3, Issue 1, March 2017, Pages 68-78
Tuo Huang | Xiang Zhou | Huaijun Yang | Guangzhi Liao | Fanhua Zeng

© 2017 Southwest Petroleum University CO2flooding is one of the most promising techniques to enhance both light and heavy oil recovery. In light oil recovery, the production pressure in CO2flooding in general keeps constant in order to maintain the miscibility of injected CO2and crude oil; while in heavy oil recovery, a depleting pressure scheme may be able to induce foamy oil flow, thus the oil recovery could be further enhanced. In this study, different pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one. Numerical simulations were conducted to history match all experimental data to understand the mechanisms and characteristics of different CO2flooding strategies. For the core-flooding experiments, 1500 mD sandstone cores, formation brine and a heavy oil sample with a viscosity of about 869.3 cp at reservoir condition (55 °C and 11 MPa) were used. Before each CO2flooding test, early stage water-flooding was conducted until the water cut reached 90%. Different CO2injection rates and production pressure control strategies were tested through core-flooding experiments. Experimental results indicated that a slower CO2injection rate (2 ml/min) led to a higher recovery factor from 31.1% to 36.7%, compared with a high CO2injection rate of 7 ml/min; for the effects of different production strategies, a constant production pressure at the production port yielded a recovery factor of 31.1%; while a pressure depletion with 47.2 kPa/min at the production port yielded 7% more oil recovery; and the best pressure control scheme in which the production pressure keeping constant during CO2injection period, then depleting the model pressure with the injector shut-in yielded a recovery factor of 42.5% of the initial OOIP. For the numerical simulations study, the same oil relative permeability curve was applied to match the experimental results to all tests. Different gas relative permeability curves were obtained when the production pressure schemes are different. A much lower gas relative permeability curve and a higher critical gas saturation were achieved in the best pressure control scheme case compared to other cases. The lower gas relative permeability curve indicates that foamy oil was formed in the pressure depletion processes. Through this study, it is suggested that the pressure control scheme can be optimized in order to maximize the CO2injection performance for enhanced heavy oil recovery.

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