Low Permeability Carbonate Reservoirs Research Articles

Ichnofabrics and their roles in the modification of petrophysical properties: A case study of the Ordovician Majiagou Formation, northwest Henan Province, China

The carbonate rocks of the Ordovician Majiagou Formation from the northwestern part of Henan Province and their diverse trace fossils provide an outcrop analogue for bioturbated, low porosity and low permeability carbonate reservoirs. Three ichnofabrics can be defined based on the ichnotaxonomy, ichnodiversities, individual abundances and overall bioturbation indices. The Balanoglossites ichnofabric represented medium to relatively high-energy sedimentary environments such as intertidal zone and subtidal shoals in the carbonate platform. The Planolites ichnofabric suggested relatively low-energy, protected sedimentary environments such as lagoons in a restricted carbonate platform, but also occurs in the deeper-water depressions in the open carbonate platform. The Chondrites ichnofabric characterized low-energy and reduced oxygen conditions, with burrows penetrating below a shallow redox interface in deeper-water settings that include the distal slope as well as local depressions in the open carbonate platform. Our analysis suggests that the modifications of petrophysical parameters are controlled or influenced by the ichnofabric characteristics (burrow architecture, burrow cross-cutting relationship, degree of bioturbation and burrow connectivity), the permeability contrast between burrow-fills and matrix, and the dolomitization of burrow-fills. The micritic host sediments have negligible porosity and permeability. The bioturbated sediments have significant differences in fabric, texture, porosity and permeability. The burrow-fills are very commonly dolomitised. Each of the burrow-types can enhance reservoir properties, but the greatest differences are associated with the Balanoglossites ichnofabric, in which porosity and permeability can reach over 2% and 70 mD. Preliminary stratigraphic studies indicate that reservoir potential in the subsurface will be linked to an understanding of the distribution of shoal and intertidal facies as well as their associated Balanoglossites ichnofabrics.

A New Drilling Fluid System for Temporary Plugging of Low Permeability Carbonate Reservoirs Containing H2S and CO2

Carbonate reservoirs in Asmari block of Missan oilfield are characterized by complex geological characteristics. Temporary plugging is commonly used for effective damage control caused by the working fluid when drilling in such complex multi-pressure reservoirs and for preventing leakage, blowout, and collapse in long open hole wells. In this paper a new temporary plugging drilling fluid formulation system is proposed, designed for the low permeability carbonate reservoir containing H2S and CO2 in the target block. The system contains a specially designed acid-soluble temporary plugging agent DSK-1 combined with HCOONa and modified biopolymer VS-A flow pattern regulator; modified starch water loss reduce agent, and DSP antioxidant. The parameters of the system, including temperature stability, resistance to formation water pollution, inhibition capacity, and stability to acids and acid gases, were evaluated in a series of experimental tests. The plugging ability was evaluated by experiments on cores received from the target block. The results showed that the plugging removal and recovery rate of the drilling fluid system was up to 86.3%, which can effectively meet the target requirements, and provide guidance and reference for the follow-up study of temporary plugging in low permeability carbonate reservoirs.

Comparison of three miscible injectants for a high-temperature, volatile oil reservoir - With particular emphasis on nitrogen injection

Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. Miscible nitrogen injection into oil reservoirs is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility.In this paper, we investigate the potential for applying miscible nitrogen injection for a high-temperature, low-permeability carbonate reservoir, which contains a volatile oil with some H2S and CO2. The field is still in its early development phase but suffers from relatively low throughput rate because of low permeability. At the prevailing reservoir pressures, extensive phase behavior studies confirm that the reservoir fluids develop miscibility with nitrogen, carbon dioxide, and hydrocarbon gas.Nitrogen behaves differently from hydrocarbon gas, despite the fact that the two gases lead to similar minimum miscibility pressures. At the prevailing reservoir pressure, the swelling factor with hydrocarbon gas is four times higher than for nitrogen. Furthermore, the reservoir fluid density increases during swelling with nitrogen, whereas it decreases as a result of hydrocarbon gas swelling. The same trend is observed for viscosity. Injection gas blends with various proportions of nitrogen and carbon dioxide shows that the MMP is constant when more than 35–40% nitrogen is present in the blend.The simulation studies involve a number of sensitivity runs performed on sector models, which are sufficiently fine-gridded to capture the compositional transition zone propagating between injector and producer pairs. Miscible nitrogen injection comes out as a viable option with the potential to increase recovery by 10–20% above the current water flood development scheme. The significantly improved sweep and displacement efficiency are due to N2 miscibility with reservoir oil under reservoir conditions, possibility of increased PV injected in a N2 WAG scheme, and the ability to maintain the initial reservoir pressure.

Transport of Associative Polymers in Low-Permeability Carbonates

Carbonate reservoirs are heterogeneous from pore scale to field scale. Waterflood in carbonate reservoirs often leaves behind a substantial amount of oil due to pore-scale and large-scale bypassing. Polymer flooding can improve sweep efficiency and oil production. Most EOR polymers cannot be transported through low-permeability (< 30 mD) rocks. Hydrophobically modified associative polymers (APs) associate with each other during passage through pore throats and give a larger flow resistance than conventional polymers (Flopaam) of the same molecular weight. The goal of this work is to investigate the transport of associative polymers in low-permeability carbonate reservoirs (less than 50 md). An associative polymer similar in molecular weight to Flopaam 3330 was investigated in this study. Polymer rheology and the effect of salinity were studied at 60 °C. Mechanical shearing and aggressive filtration were used to modify the particle size distribution in polymeric solutions and improve transport through tight cores. Single-phase polymer transport experiments were performed in outcrop Edwards Yellow and Indiana limestone cores. Mechanical shear degradation reduced the particle size and improved the transport of the associative polymer in low-permeability carbonate cores. The permeability reduction factor and the residual resistance factor were higher for the sheared AP polymers than those for the sheared Flopaam polymer. The resistance factors for the associative polymer were higher than those for Flopaam for a given shear viscosity. Coreflood experiments with AP showed the evidence of two propagation fronts: polymer concentration front and pressure gradient stabilization front due to polymer network formation and polymer adsorption. As AP polymer concentration increased, permeability reduction factor, resistance factor, residual resistance factor and polymer adsorption increased. All the coreflood experiments suggest successful polymer transport in low-permeability carbonate cores even at significantly high polymer concentrations with pre-shearing.

Low-tension gas process in high-salinity and low-permeability reservoirs

Polymer-based EOR methods in low-permeability reservoirs face injectivity issues and increased fracturing due to near wellbore plugging, as well as high-pressure gradients in these reservoirs. Polymer may cause pore blockage and undergo shear degradation and even oxidative degradation at high temperatures in the presence of very hard brine. Low-tension gas (LTG) flooding has the potential to be applied successfully for low-permeability carbonate reservoirs even in the presence of high formation brine salinity. In LTG flooding, the interfacial tension between oil and water is reduced to ultra-low values (10−3 dyne/cm) by injecting an optimized surfactant formulation to maximize mobilization of residual oil post-waterflood. Gas (nitrogen, hydrocarbon gases or CO2) is co-injected along with the surfactant slug to generate in situ foam which reduces the mobility ratio between the displaced (oil) and displacing phases, thus improving the displacement efficiency of the oil. In this work, the mechanism governing LTG flooding in low-permeability, high-salinity reservoirs was studied at a microscopic level using microemulsion properties and on a macroscopic scale by laboratory-scale coreflooding experiments. The main injection parameters studied were injected slug salinity and the interrelation between surfactant concentration and injected foam quality, and how they influence oil mobilization and displacement efficiency. Qualitative assessment of the results was performed by studying oil recovery, oil fractional flow, oil bank breakthrough and effluent salinity and pressure drop characteristics.

DIGITAL CORE TECHNOLOGY APPLICATION AT SARQALA FIELD

An integrated laboratory study of low permeable carbonate reservoir (dolomitic limestones, Sarqala field) included a digital rock (DR) workflow that accelerated the time to complete the core analysis program, in a case when the standard is ineffective. All these data were used to justify the field development strategy.

Low tension gas flooding for secondary oil recovery in low-permeability, high-salinity reservoirs

Low Tension Gas (LTG) flooding has been established as a successful tertiary oil recovery method for low-permeability carbonate reservoirs with high salinity and hard formation brine (~200,000 ppm and hardness 19,000 ppm). LTG flooding recovers oil using two integral mechanisms: ultra-low interfacial tension (IFT) between oil and water, and mobility control using in-situ foam generated by injected gas. In the present work, the scope of applicability of LTG flooding has been extended to secondary oil recovery under the same reservoir conditions. Secondary recovery using LTG flooding has been compared to conventional secondary recovery methods such as waterflooding. Oil recovery was observed to increase by 16% OOIP (Original Oil in Place) as compared to waterflooding, even in case of micellar flooding without gas. On introducing mobility control during LTG flooding in the form of injected gas, the secondary oil recovery was observed to increase steadily up to 81% OOIP. Co-injecting gas and surfactant also exhibited lower pressure drop than waterflood, thus underlining the importance and efficiency of mobility control using foam in secondary recovery. Gas injection strategy was improved in terms of injected foam quality and onset of gas injection. When gas was injected only during drive, ultimate oil recovery was reduced to 70% OOIP. Chemical injection strategy was also modified to test the impact of different in-situ salinity profiles on oil recovery.

Experimental study of injection strategy for Low-Tension-Gas flooding in low permeability, high salinity carbonate reservoirs

Previous experimental studies have proven that Low-Tension-Gas (LTG) flooding can be a suitable enhanced oil recovery (EOR) method for low-permeability carbonate reservoirs with high salinity and hard formation brine. LTG flooding was observed to improve oil recovery by combining two effects: a reduction of the interfacial tension (IFT) between oil and water and mobility control through the formation of in-situ foam with an injected gas. However, the high cost of chemicals and/or the limited supply of gas could make this process economically challenging.In this study, the primary goal was to reduce the amount of injected gas and surfactant to make the LTG process more economically feasible. A low-permeable (<10 mD) limestone reservoir with a high formation brine salinity (>200,000 ppm and hardness 19,000 ppm) and temperature 69 °C was the target reservoir of this study. Effect of varying the concentration and pore volumes of the ultra-low IFT inducing surfactant slug injected on oil recovery was studied. Nitrogen gas was co-injected during selected time periods throughout the entire surfactant injection in order to identify the significance of mobility control during the crucial phases of the LTG flooding. The coreflood results emphasized the significance of the injection of gas, even at lower foam quality, for the maintenance of mobility control. Ultimate oil recovery of over 60% (residual oil post waterflood) was achieved, even after reducing the surfactant concentration by 75% and inducing a different in-situ salinity profile as compared to earlier studies. An innovative method for measuring surfactant adsorption using Liquid Chromatography and Mass Spectrometry (LC-MS) was developed, which could provide individual surfactant transport data for each of the three classes of surfactants used.

Laboratory treatment of HPAM polymers for injection in low permeability carbonate reservoirs

Polymeric solutions are injected into petroleum reservoirs to improve sweep efficiency of enhanced oil recovery processes. Viscous polymeric solutions cannot be injected into non-fractured low permeability carbonates (k < 50 mD) if a significant fraction of pore throats is smaller than the polymer molecules. Mechanical shear degradation and aggressive microfiltration can be applied as tools to modify the molecular weight distribution (or hydrodynamic radius) of polymers. High speed mechanical shearing in a laboratory blender showed significant reduction in viscosity and polydispersity for the polymer stock solutions with improvement in filterability and transport in low permeability porous media. Aggressive filtration through small sized filter papers proved to be a good technique for refinement of molecular weight distribution and removing larger molecules for successful injection in low permeability carbonates. Dynamic light scattering (DLS) method was used to measure the size distribution of shear degraded polymer solutions at low concentrations. The optimum shear degradation required for a high MW polymer to be successfully injected into a low permeability carbonate reservoir was decided by comparing the polymer size distribution with the pore throat diameter distribution obtained from mercury injection capillary pressure (MICP) for the rock. This novel technique was successfully applied for injection of viscous polymer solutions in carbonates with permeability less than 20 mD. The pore throat distribution of a porous medium is more important than the permeability (or average hydraulic radius) for the transport of polymers in porous media.

CO2 Storage in Low Permeable Carbonate Reservoirs: Permeability and Interfacial Tension (IFT) Changes During CO2 Injection in an Iranian Carbonate Reservoir

The lack of fundamental experimental studies on low permeable carbonate reservoirs for CO2 sequestration purposes is essential for further application of CO2 sequestration as a highly-anticipated CO2 mitigation method in deep saline aquifers, specifically those with low permeabilities. The core samples were taken from a carbonate reservoir in Iran and the brine composition was based on that of the same formation. The objective of this study is to investigate permeability alteration during CO2 sequestration in the aquifers of a low permeable Iranian carbonate reservoir. Various parameters have been investigated. The effects of different parameters such as injection pressure, confining pressure, and temperature on permeability alteration of the cores was investigated. Moreover, the interfacial tension (IFT) of CO2/brine was also determined at pressures and temperatures up to 7 MPa and 100 °C, respectively. The experimental results showed CO2 solubility and rock dissolution to be the governing mechanism when CO2 was injected into carbonate cores. The permeability measurements showed that permeability increases by increasing injection pressure and decreases by increasing confining pressure and temperature. The IFT measurement results showed that the IFT decreases significantly when there is an increase in pressure and temperature.

Post-oil-migration structural deformation: a possible mechanism for the genesis of the tilted oil–water contact of the Mumbai High Oilfield, India

The presence of a complicated, variable-depth oil–water contact (OWC) in the Early Miocene L-III carbonate reservoir of the Mumbai High Oilfield has been well established. The OWC dips towards the SW along a curved profile, but the gas–oil contact (GOC) is flat. Very little is known about the possible mechanisms that could have produced this complex fluid contact. In the absence of a horizontal pressure gradient, gravity should produce a flat OWC. In many fields around the world, where non-flat fluid contacts are observed, the contacts could be described as segmented, tilted or curved OWCs. Commonly believed mechanisms which produce such types of contacts are: fault compartmentalization, hydrodynamic flow, ongoing charge; and reservoir property variation. All these mechanisms fail to explain the tilted OWC of the Mumbai High. This paper proposes that another mechanism – structural adjustments after the migration of hydrocarbons into the palaeotrap – might have resulted in tilting or curving of the originally flat OWC of the Mumbai High. Such a phenomenon is likely to be observed in oil-wet low-permeability carbonate reservoirs. Imbibition-related hysteresis combined with diagenesis-induced property degradation in the water leg are the possible mechanisms that can prevent the OWC from equilibrating even after cessation of structural evolution.

РАЗРАБОТКА ДИЗАЙНА ГИДРОДИНАМИЧЕСКОГО ИССЛЕДОВАНИЯ В УСЛОВИЯХ КАРБОНАТНОГО КОЛЛЕКТОРА

Актуальность исследования обусловлена необходимостью совершенствования методов гидродинамических исследований скважин вследствие неоднозначности интерпретации результатов в условиях карбонатного коллектора. Приоритетами при проведении гидродинамических исследований скважин являются максимальное качество получаемой информации о фильтрационно-емкостных свойствах пластов и минимальные потери добычи нефти в ходе остановки скважин на исследования. С целью выполнения данных задач актуальной является разработка дизайна гидродинамических исследований скважин, предлагаемая в статье. Дизайн позволит обеспечить комплексный подход к моделированию процесса проведения исследований и прогноза получаемых данных. Цель: разработать дизайн гидродинамических исследований скважин с целью оптимизации времени проведения исследований и сокращения периода остановки скважин на этапе опытно-промышленной эксплуатации; подтвердить экономическую эффективность представленной методики. Объекты: скважины Т-23, Т-361, Т-388 месторождения A, продуктивные отложения которого преимущественно представлены кавернозно-трещиноватыми карбонатными породами рифейского возраста. Методы. Поставленные задачи исследования решались теоретически и экспериментально в промысловых условиях. При этом был выполнен анализ публикаций по данной проблеме; проведены промысловые гидродинамические исследования скважин, вскрывающих низкопроницаемый карбонатный коллектор; выполнено моделирование гидродинамических исследований, выполнены сравнительные расчёты по обработке результатов с помощью программного комплекса Saphir компании «KAPPA Engineering». Результаты. Приведены результаты разработки дизайна гидродинамических исследований в условиях карбонатного коллектора. Проанализированы данные гидродинамических исследований для 12 скважин, эксплуатирующих рифейские карбонатные отложения, за период с 2005–2008 гг. представлены результаты по трем скважинам: Т-23, Т-361, Т-388. Представлена методика моделирования гидродинамических исследований в программном комплексе Saphir компании «KAPPA Engineering». Приведен пример расчета времени стабилизации при исследовании скважины методом установившихся отборов, а также оценка оптимального времени регистрации кривой восстановления давления. Также приведено сравнение стандартной методики, которой руководствуются при испытании скважины – РД (руководящий документ) 153-39.0-109-01 «Методические указания по комплексированию и этапность выполнения геофизических, гидродинамических и геохимических исследований нефтяных и нефтегазовых месторождений», с методикой, представленной в статье. На основе данного сравнения была установлена экономическая эффективность.

Measurement of Damköhler number on the X-Ray computed tomography basis in the process of heavy oil carbonate reservoir acidizing

Nowadays, cases of the joint use of thermal and chemical methods of enhanced oil recovery have become more frequent. In this regard, acid treatment has an important role, which allows increasing the productivity of wells with low-permeability carbonate reservoirs. At the experimental level, the presence of an optimal injection mode has been proven, that depends on the dimensionless of Damköhler number and leads to the formation of “wormholes” of dissolution with increasing reservoir permeability. In this work, a new optimized method for calculating the Damköhler number based on X-ray computed tomography data is proposed. A comparison of the calculation of values by the classical and the new technique for different wormholes is presented.

Study of surfactant alternating gas injection (SAG) in gas-flooded oil-wet, low permeability carbonate rocks

Many low permeability carbonate reservoirs are gasflooded but leave behind a large amount of residual oil. Surfactant solutions can be injected with gas to improve recovery. Surfactants and gas have the potential to form foam that can improve both oil displacement efficiency and sweep efficiency in oil reservoirs. However, in many carbonate reservoirs, foams need to overcome two adverse conditions: oil-wettability and low permeability. This study investigates the performance of 2 surfactant formulations in gas-flooded low permeability, oil-wet carbonate cores: one that combine wettability alteration, low interfacial tension (IFT), and coarse foaming and the other that is only foaming. Phase behavior experiments were performed to determine the optimal salinity for low oil-water IFT. Contact angle and imbibition experiments were performed on initially oil-wet media to identify surfactants for wettability altering capabilities. Coinjection coreflood experiments of surfactant solution and gas (with no crude oil) were performed at a constant injection rate with varying gas/water ratio and at varying injection rates to determine the critical foam parameters. Finally, oil displacement experiments were performed in low permeability limestone cores using the promising surfactant formulations to study the effect on incremental oil recovery after gas EOR injection process. In addition, dynamic adsorption tests were performed to estimate the adsorption of surfactants in limestone rocks. Mobility reduction factors obtained in coinjection experiments were low (less than 10 in most cases) in tight carbonate cores. The foaming was very coarse or weak, if any. There was a significant hysteresis effect at higher foam injection velocity; the foaming behavior in low permeability carbonate rocks were very weak and very different compared to those in high permeability rocks. Wettability alteration and low IFT can be achieved with anionic surfactants that generate coarse foam and help in fluid diversion. Adsorption of the anionic surfactants studied was between 0.04 and 0.11 mg/gm of rock in presence of alkali and EDTA in tight carbonate formations. Oil displacement experiments in oil-wet carbonate cores revealed that tertiary oil-recovery with injection of wettability-altering, low IFT surfactant can recover a significant amount of oil (about 28–70% ROIP) over the secondary gas flood. The pressure drops in the presence of oil suggested rapid foam coalescence and unstable foam in oil-wet carbonate cores. Good foaming surfactant that does not change wettability or achieve low IFT recovered less oil. Low IFT and wettability alteration in synergy with coarse foaming improves incremental oil recovery significantly and is crucial for higher oil recovery in oil-wet porous media.

Optimization of the horizontal-well multiple hydraulic fracturing operation in a low-permeability carbonate reservoir using fully coupled XFEM model

Pre-analysis of the geometry and deviation of multiple hydraulically induced fractures is a decisive factor in the successful multiple hydraulic fracturing operations. Besides, fracture spacing should be optimal for obtaining desired results such as maintaining sufficient aperture for proppant placement, avoiding screen-outs and also preventing fracture closure or crossing multiple fractures. In fact, the final geometry and deviation of multiple hydraulic fractures are dramatically influenced by the interaction of multiple hydraulic fractures on each other known as stress shadow effect which is caused by fracture spacing and pore pressure change. Predicting the geometry and deviation of multiple hydraulic fractures is a challenging part of conducting this technology in Ilam reservoir due to low matrix permeability and naturally fractured nature of the reservoir. Accordingly, a fully coupled stress-diffusion XFEM model for initiation and propagation of multiple hydraulic fractures with five injection zones was prepared to optimize the effect of fracture spacing and pore pressure change on the multiple hydraulic fractures’ deviation and geometry. Additionally, the XFEM model was verified by three approaches including field data, Stress Intensity Factor and KGD zero toughness solution wherein a very good agreement with negligible error was obtained for SIF, field data and KGD M-vertex solution. However, this study has confirmed that both pore pressure and stress shadows contribute to change the fracture geometry and its deviation significantly in Ilam reservoir. Also, increasing pore pressure between fractures, may affect the fracture geometry to be tighter in width and shorter in length. In addition, considering optimized fracture spacing about 75 m resulted in creation of very smooth, uniform and deeper multiple hydraulic fractures; so, there will be no closed fractures in DPH-02 horizontal wellbore and the possibility of crossing the furthest fracture by the second fracture significantly reduced when the fracture spacing was higher than 5 m.

Physical Simulation of Colayer Water Flooding in Low Permeability Carbonate Reservoir in Middle East

To study the flow mechanism under different displacement modes of low permeability carbonate reservoir in the Middle East and to improve the utilization of various types of reservoirs, the physical simulation experiments of water flooding by different displacement methods were carried out. Selecting two types of rock samples with different permeability levels, two-layer coinjection and separated production experiments by samples I and III and conventional water flooding experiments by samples II and IV were carried out. In addition, by using low magnetic field nuclear magnetic resonance, the development effect of microscopic pore structure under the different injection-production models was analyzed. Results show that, compared with the coinjection, the recovery rate of sample I was higher than II, 19.30%; sample III was lower than IV, 23.22%; and the comprehensive recovery degree reduced by 3.92%. NMR data also show that the crude oil is mainly distributed in the large pore throat; after water flooding, the displacement is also within the large pore throat, whereas the small pore throat is mainly obtained by the effect of infiltration absorption. The above studies provide a laboratory basis and foundation for the further development of low permeability carbonate reservoir in different Middle East strata.

Low salinity water–Surfactant–CO 2 EOR

Coreflood, interfacial tension (IFT), contact angle, and phase behavior measurements were performed to investigate the viability of a hybrid of low-salinity water, surfactant, and CO2 flood enhanced oil recovery (EOR) process. Low-permeability carbonate reservoir cores were aged for eight weeks at reservoir temperature and pressure. Coreflood and contact angle between oil droplets and core surface measurements were performed. Additional contact angle measurements on sandstone and shale cores were also performed. The coreflood sequences were seawater flood, followed by low-salinity water flood, followed by surfactant floods until residual oil saturations to each flooding sequences and finally CO2 injection. Coreflood in low-permeability carbonate cores show that the hybrid EOR process produces incremental oil up to twenty-five percent beyond seawater flooding. Contact angle measurements on carbonate, sandstone and shale cores indicate that wettability alteration and IFT decrease are the main oil-mobilizing mechanisms in the hybrid EOR process. The hybrid EOR process mobilizes part of the residual oil because: (i) low-salinity brine improves wettability towards hydrophilic condition favorable for surfactant flooding; (ii) surfactant in low-salinity water solubilizes some of the remaining oil as Winsor type II− microemulsion and lowers IFT between oil and water; and (iii) CO2 will follow surfactant to mobilize more of the remaining oil in the wettability-improved condition.

Effects of Nanoparticles on Gas Production, Viscosity Reduction, and Foam Formation during Nanofluid Alternating Gas Injection in Low and High Permeable Carbonate Reservoirs

AbstractSome carbonate reservoirs are low‐permeable and mixed‐wet to oil‐wet. Application of enhanced recovery methods to decrease residual oil saturation is the main challenge in such reservoirs. Water‐flooding is not an appropriate method to improve the recovery due to the wettability of carbonate reservoirs. Water alternating gas (WAG) injection is used as another method but it faces some problems. To enhance the performance of the WAG method, the wettability of rock should be changed and mobility of the injected gas should be controlled.In our previous study (Moradi et al.[32]), to improve the WAG‐EOR process and overcome the problems, we developed the nanofluid‐alternating gas (NWAG) approach by adding nanoparticles to the aqueous phase. Our study indicated that the NWAG process could improve oil recovery in comparison to the conventional WAG method in different core samples with different lithology and permeability. In this study, core‐flooding experiments, dynamic foam generation, and viscosity measurement were performed to investigate the effect of nanoparticles on gas production, viscosity reduction, and possibility of foam formation in the NWAG process. The results indicated that the gas production was decreased in the NWAG process. In addition, viscosity of produced oil was lower in the NWAG process; CO2 dissolved in the oil and led to oil swelling and oil viscosity reduction. Oil recovery was higher in the samples with lower permeability due to the formation of foam in the porous media. Foam formation increased viscosity and controlled mobility, which led to better sweep efficiency.

Technology Focus: Matrix Stimulation (June 2016)

Technology Focus It goes without saying that the oil and gas industry faces unprecedented challenges today. Low oil prices are driving continued improvements in efficiency and a search for technologies to deliver barrels at the lowest possible cost. Health, safety, and environmental (HSE) impacts of chemicals used in drilling, completion, and production operations are under increased scrutiny from regulatory and community stakeholders. At the same time, more and more complex and technically challenging reservoirs must be developed to replace reserves. Matrix stimulation is being used to maintain production from existing wells and reservoirs and maximize production from new wells at an attractive cost per incremental barrel. Close cooperation between suppliers, service companies, and operators is required to deliver systems-level lifecycle solutions that leverage the HSE benefit to improve effectiveness and operational efficiency. Over nearly a century of application and study, acidizing technologies have been matured for relatively pure carbonates, clean sandstones (less than 10% carbonate), and temperatures below approximately 100°C. Today, the industry is developing reservoirs that have more complex mineralogy, greater permeability contrast, and higher temperatures. New chemistries are being deployed to control the aggressiveness of stimulation fluids at high temperatures and to minimize the effect of unwanted damaging precipitation reactions. Sandstone matrix acidizing traditionally requires the use of a carefully designed sequence of stages to manage the complex reactions between hydrofluoric acid and siliceous minerals. New formulations that can be applied at higher temperatures and sometimes with a single stage have been developed and deployed in the field. In addition to increasing the potential application range and effectiveness, these formulations reduce the chemical footprint of sandstone stimulation. Laboratory data indicate that they are very effective but must be tailored carefully to the target reservoir. Continued experiments, theoretical modeling, and field testing are needed to understand and achieve the full benefits of deploying these new technologies. In low-permeability carbonate reservoirs, acid stimulation is a low-cost alternative to propped hydraulic fracturing. New chemical and mechanical diversion technologies are being deployed to enable creation of distributed etched-fracture and wormhole networks along long interval and multilateral wells in low-permeability and heterogeneous reservoirs. These technologies are being taken up across the globe and are delivering optimized treatment designs and execution on a large scale. Finally, there is an ongoing effort to use state-of-the-art simulation technologies (e.g., computational fluid dynamics) to model complex coupled reaction and flow processes and improve the understanding of stimulation processes and interpretation of more detailed data now available (e.g., from distributed-temperature sensing). Matrix stimulation remains a critical technology for delivering barrels at minimum cost. It is finding application in unconventional as well as conventional-reservoir development. Chemical formulations and theoretical models continue to develop, sometimes incrementally and sometimes in step changes, to broaden the scope of application, improve effectiveness, reduce cost, and reduce HSE impact. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 173686 Optimization of Matrix Acidizing With Fluids Diversion in Real Time Using Distributed-Temperature Sensing and Coiled Tubing by Eber Medina, Pinnacle, et al. SPE 179001 Field Results and Experimental Comparative Analysis of Sodium- and Nonsodium-Chelant-Based HF Acidizing Fluids for Sand-Control Operations by Alyssa LaBlanc Smith, Halliburton, et al. SPE 179017 An Improved Wormhole- Propagation Model With a Field Example by Xuehao Tan, Schlumberger, et al.

Bitumen Prices and Structural Changes in North American Crude Oil Markets

In an earlier report, changes in bitumen prices at Hardesty, Alberta, Canada, were modeled as the responses to changes in monthly prices of Hardesty light/medium crude oil for the period 2000–2006 with a simple error correction econometric model. This note re-examines that price relationship for the period 2009–2014. Over the period 2006–2014, there was also rapid growth in North American light oil production from low-permeability carbonate, sandstone, and shale reservoirs. During that period, Canadian raw bitumen production grew by more than 12% per year and there was significant geographical diversification in its markets. Results of the statistical analysis showed that the change in the dynamic relationships between bitumen prices and Hardesty light oil prices probably reflected, in part, the maturation of bitumen markets and closer integration with North American light oil markets. The analysis also examines the dynamic relationships between bitumen prices and West Texas Intermediate and Brent international benchmark crude oil prices. Ideally, if bitumen prices are found to be closely related to a widely traded benchmark crude oil, the benchmark crude oil price forecasts could be used as a basis for predicting bitumen prices. However, neither of international benchmark crude oils tested had high explanatory power.