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The Yariguí-Cantagallo is a mature oil field located in the western flank of the middle Magdalena valley basin in Colombia. Oil production started in 1941 and has been supported by water injection since 2008 with the aim of maintaining the pressure in the reservoir and increasing oil production. However, due to the channeling of the injected water, the water cut in some wells has been increasing, reaching values greater than 90%. Therefore, ECOPETROL S.A. implemented the first deep conformance treatment in Colombia through the design, execution, monitoring and evaluation of the technology in the YR-521 and YR-517 patterns for improving sweep efficiency of the waterflooding process. Brightwater® technology (also known as Thermally Active Polymer, TAP) has been used as an in-depth conformance improvement agent in reservoirs under waterflood suffering from the presence of thief zones or preferential flow channels. BrightWater® consists of expandable submicron particles injected downhole with a dispersive surfactant as a batch using injection water as a carrier. The selection of the injection patterns and treatment volume estimation was carried out through analysis of diagnostic plots and analytical pattern simulations. Treatment design and chemistry selection were based on reservoir characteristics, especially the temperature profile between the injector and offset producing wells in each pattern. Thus, laboratory tests with the representative fluids at various temperatures were carried out. Injection in the first pattern began on December 14, 2020, with a cumulative 6344 bbls of water containing TAP, at an injection rate of 700 bpd, gradually increasing the concentration from 3,500 ppm to 12,000 ppm. Once the injection was completed in this pattern and using the same surface facility, the second injection pattern was executed, on December 23, 2020. In the second pattern a cumulative of 9152 bbls of water containing TAP was injected at an injection rate of 700 bpd at concentration from 3500 ppm up to 8000 ppm. This paper summarizes the first TAP pilot implementation in Colombia and will describe the methodology and results of project QAQC monitoring and injection-production. Based on results to date, after one year monitoring (decrease in water cut up to 6%, in some wells, with consequent increase in oil recovery up to 18,642 STB), five additional treatments are planned in other injection patterns in this field between 2022 and 2023. It was validated that the deep conformance improvement technology allows blocking the preferential flow channels, reaching new areas with high oil saturation. Incremental oil production, potential increase in reserves, and reduction of OPEX due to lower water production were some of the observed benefits from this trial. Likewise, calculations show positive impacts in reducing the carbon footprint and water management.

The Meymand world heritage site (Kerman Province, Iran) is a rock-hewn village carved within a pyroclastic rock mass, Meymand Tuff. This site, having an ancient local population with an age of 2000 years, is hosted by a weak rock exposed to deterioration and weathering processes. However, our understanding of the characteristics of the Meymand Tuff is limited to some previous general studies. Therefore, in the present study, the stratigraphy and intrinsic characteristics of the Meymand tuff are investigated to determine its weathering behavior and durability. For this purpose, comprehensive field and laboratory investigations were carried out. The stratigraphy of the valley and the pyroclastic flows that had deposited the Meymand tuff were identified and outlined based on field investigations and many surveyed sections along the Meymand valley. Next, the mineralogical composition, texture, structure, physical and mechanical properties, water absorption rate, slake durability, wetting–drying durability, shrinkage potential of the fine portion, and collapse potential of the Meymand tuff were assessed through laboratory investigations. The results revealed that two pyroclastic flows had deposited the host tuff rocks of the Meymand site. These rocks have a heterogeneous texture comprising very coarse-grained clasts to the fine-grained matrix. Rock characteristics including heterogeneous texture, high porous and open structure, clay-rich mineralogical composition, high water absorption capacity, and swelling and shrinkage potential of the fine portion of the matrix have resulted in adverse behaviors in Meymand tuff. These behaviors are pertained to the strength softening, weight loss, and deterioration at wetting drying cycles. This study was funded by a grant from Iran National Science Foundation (INSF) (98001268).

A simple technique to design stable gain and low back lobe substrate-integrated waveguide (SIW) horn antenna is proposed. Matching is achieved by placing a metallised via in a specific distance fro...

The interplay among reservoir heterogeneities, structural complexities and unfavorable mobility ratios are usually responsible for premature water breakthrough in brown fields across the world. Recently, a deep conformance control technology, known as Thermally Activated Particle (TAP), has been successful in addressing this challenge. Limited intervention and lower deployment cost make it very attractive for mature waterflooded fields. Cerro Dragón is a giant field located in San Jorge Gulf basin with multi-layered channel deposits. Presence of highly conductive channels and unfavorable mobility ratios have severely impacted the sweep efficiency, resulting in low oil recovery and high water production. Building on the learnings from the previous pilots, TAP has been recently deployed at a segment scale in one of the blocks of Cerro Dragón field. This paper shares the technical details behind the screening, designing and the deployment of TAP technology. After initial screening of multiple candidates, a reservoir segment has been selected for TAP implementation. Inter well tracer data with comprehensive injection/production data analysis identified the communicating wells and thief zones volumes were then estimated around each injector. The estimated thief zones volumes were also confirmed by volumetric calculation. Thermal modeling and numerical simulation were utilized using a representative and history matched model to finalize the size, concentration and the proper activation of injected TAP molecules. Subsequently, in early 2018, nearly 360 metric tons of TAP was safely deployed into six target injectors. This campaign met all design guidelines, all planned surveillance data was acquired, and the project was executed on time and on budget. Post deployment, frequent sampling at offset producers was performed confirming no breakthrough of un-activated polymeric particles. Oil rates and WOR trends are currently being monitored, as part of the longer-term surveillance plan, to quantify incremental benefits from TAP EOR technology. Previous 2011 implementation and positive results in other segments of the field were an important input and they are also described in this paper. The results of this treatment will provide very helpful guidelines that can be used in any brown fields to improve the efficiency of waterflooding especially in highly heterogeneous reservoirs with low waterflooding performance.

A simple technique to reduce the mutual coupling between patch antenna arrays is proposed. Mutual coupling phenomena in patch antenna array are investigated and according to the coupling characteristics, a simple rectangular slot(s) placed in between the patch elements is proposed. An equivalent circuit of the proposed structure is obtained through the reciprocity method. In the proposed technique, the series equivalent circuit of the slot is used to reduce the mutual coupling level without changes to the back lobe as well as cross-polarisation levels compared to conventional arrays. The mutual coupling reduction is >20 dB when compared with the conventional array. Applied to a phased array antenna, the reduction in the mutual coupling results in a wider scan range, up to 75°. A parametric study is carried out for different parameters of the slot that affect the mutual coupling and the scan range. A prototype of the antenna array is fabricated and the measured results are compared to the simulation.

In recent years, the United States (US) has experienced a resurrection in hydrocarbon recovery owing to the extraction of oil and gas from unconventional resources. Due to the ultra-low permeability nature of these reservoirs and their oil-wet characteristics, oil production declines are steep and oil recoveries remain very low (< 12% of OOIP). This challenge endures even with the assistance of hydraulic fracturing advancements and well spacing optimizations. The billions of barrels of remaining oil is a good target for chemical enhanced oil recovery (EOR) technologies.In this study, after comprehensive laboratory testing, a series of customized chemical formulations was developed to improve oil recovery under the challenging conditions of the Middle Bakken and Niobrara formations (temperature >110 °C, salinity>220,000 ppm, and hardness>15,000 ppm). To examine the performance of the selected formulation in the field-scale, a single well enhancement trial was carried out. A detailed review of the lab and field data (pre-and post- treatment) is discussed in this study. Oil rate decline analysis and numerical simulations were used to obtain more insight about the true effectiveness of the chemical treatments. The results of this field trial reveal that injecting a proper wettability altering agent can improve oil recovery from shale oil reservoirs by up to 25% of the estimated ultimate recovery (EUR). The results of numerical simulations also show that the additional oil recovered in this field trial cannot be achieved by either well shut-in or straight water injection.The lessons learned from this study provide practical information to optimize similar field trial designs leading to more profitable projects. The concepts and information here can be also translated to other unconventional basins and gas condensate or wet/dry gas reservoirs.

Several surfactant formulations that had been tested successfully in oil-wet unconventional reservoirs were tested in mixed-wet to oil-wet unconventional reservoir cores and did not generate the expected results. To study the mechanisms of oil recovery and understand the uniqueness of these shale reservoirs, a series of studies were performed utilizing Eagle Ford (EF) and Canadian Bakken shale rocks and fluids. In this study customized chemical formulations for improving production from the EF and the Canadian Bakken were developed. Previously related formulation development for the Bakken and Permian basins relied upon wettability alteration as the oil recovery mechanism; however, no significant oil recovery compared to brine was seen from wettability-altering formulations using EF and Canadian Bakken shale rock and fluids. Several imbibition tests showed that baseline oil recovery by brine was 20-30% of original oil in place (OOIP) for both formations. High oil recovery by brine was attributed to the mixed to water-wet nature of the pore surface. A well-connected fracture system may have also contributed. Further, there was no correlation between oil recovery and contact angle measurements. Failure of wettability alteration as an oil recovery mechanism led to investigation of interfacial tension (IFT) reduction as an alternative mechanism. Testing this hypothesis, a change in the EF formulation reduced IFT to 0.03 dyne/cm and had oil recoveries above 60% OOIP. However, these formulations were not stable at 320 °F. Formulation KPIs were set as lowering IFT and being stable up to 320 °F. Out of many formulations tested, two containing multiple actives in a specific mixture of solvents passed the KPIs and were tested for imbibition oil recovery. A synergistic mixture had a final oil recovery above 56% OOIP as compared to 20-25% OOIP for brine alone. The imbibition oil recovery results indicate that although the ultimate oil recovery by brine alone is significant, the early oil production is significantly slower than by surfactant solutions. Upscaling the laboratory time to the field time emphasizes the value of implementing customized surfactant formulation in both early and late oil production. Similarly, there was no correlation between wettability contact angle measurements and oil recovery for the Canadian Bakken shale. Surfactant formulations which exhibited low IFT (~0.01 dyne/cm) significantly accelerated the oil production and recovered an additional 30-45% OOIP in the tertiary mode from the imbibition tests. Further laboratory studies via the Washburn method, imbibition tests, and zeta potential measurements validated lowering IFT, not altering the wettability, as a primary oil recovery mechanism in the mixed-wet EF and Canadian Bakken. Optimal formulations for EF and Canadian Bakken will be tested in the field by mid-2018.

This paper describes the interpretation of a successful inter-well field trial of a novel reservoir-triggered polymer technology, making use of pressure transient analysis and numerical simulation. The polymer has been engineered to improve sweep in oil-bearing formations whilst reducing the impact of two of the key operational and economic challenges facing polymer enhanced oil recovery (EOR). The polymer employs a chemical strategy to render it resistant to shear during injection and in the high flux region at the sand face. In addition, the injection solution has a viscosity similar to that of water until triggered in the reservoir, which sustains injectivity. We demonstrate the use of laboratory kinetics, rheology data, high-resolution surveillance of the injector, and comprehensive analysis of produced fluids to constrain the simulation of the in-situ viscosification of this polymer. Numerical models using commercial and in-house R&D codes were calibrated to tracer effluent data, pressure fall-off tests, and injection pressures, to interpret the size and mobility of the polymer bank and its response to water injection. The field trial has qualified the polymer to be considered for deployment. A comprehensive surveillance programme and downhole sampling was used to successfully demonstrate that the polymer was protected from shear degradation upon injection and propagation, and it viscosified under flow at the designed location in the reservoir. Kinetic and rheology data from laboratory testing, combined with reservoir-scale simulations and field trial surveillance, enabled the reaction and adsorption characteristics of the polymer to be estimated. Simulations of the injection pressure demonstrate that this polymer has significantly better injectivity under matrix conditions than would be obtained with a conventional polymer of an equivalent deep-reservoir viscosity.

This paper describes the successful execution of an inter-well field trial to test a novel reservoir-triggered polymer technology (the Polymer) which has been proven to mitigate two of the major operational and economic challenges facing polymer injection for enhanced oil recovery (EOR), particularly in the offshore environment. The challenges of shear degradation and reduced injectivity are overcome by delaying the development of viscosity until the Polymer is in the reservoir. The field trial was conducted in an onshore sandstone oil field in Texas. The 1,000 ppm Polymer solution was injected at rates of 500 to 900 bbl/d into a 10-ft interval of low water permeability (50-100 mD) under matrix conditions. To demonstrate development of its expected viscosity in the reservoir, the growing Polymer bank was sampled from an existing producer. Pressure Transient Analysis (PTA) was used to confirm the deep-reservoir behaviour of the Polymer. Field data demonstrates that the Polymer behaves as intended. The viscosity of the produced Polymer samples corresponds to the target viscosity as determined from surface activation of the Polymer at the same concentration. This confirms the shear-stability of the Polymer in its un-triggered form. In addition, the injection pressures were no greater than expected and significantly lower than the expected injection pressures, under matrix conditions, for an equivalent partially-hydrolysed polyacrylamide (HPAM). PTA indicates a bank of fluid of increased viscosity some distance from the injector, as designed.

In this report, we present the application of hepatobiliary scintigraphy using Tc-99m mebrofenin in the diagnosis of bronchobiliary fistula caused by a liver hydatid cyst, which penetrated the diaphragm. Hepatobiliary scintigraphy noticeably depicted the leakage of the tracer from the biliary system of the liver to the bronchial tree. Hepatobiliary scintigraphy stands as a robust modality in the accurate diagnosis and treatment planning of bronchobiliary fistulas.

Surfactant-enhanced oil recovery (EOR) in fracture-dominated naturally fractured reservoirs (NFR) and very low-permeability Bakken type reservoirs is less known. Therefore, to predict its performance, improvement of the reservoir simulation tools is necessary to account for the surfactant flow mechanisms as much as possible. We present an improved dual-porosity (DP) numerical simulation model and algorithm in which matrix-fracture fluid transfer function was enhanced by implementing a proper viscous displacement mechanism. This mechanism was added to the existed fluid expansion, gravity drainage, and capillary pressure mechanisms. Current DP reservoir simulators generally do not account for the viscous displacement mechanism. To validate both the accuracy and efficacy of the improved model, results were compared with the results from a variable permeability-porosity, single-continuum, fine-grid model.Simulation results of improved model were in agreement with the results of the fine-grid model as the reference case. In a one-dimensional numerical model, water flood cumulative oil production increased about 5% compared to the conventional DP model. Also, incremental oil production increased over 5% for 1 to 2 wt% surfactant concentrations. Similar results were obtained in multi-dimensional numerical models. In a representative matrix block, the water flood oil production rate started at 0.25 bbl/day in improved model compared to 0.053 bbl/day in conventional DP model. This rate was 0.124 bbl/day versus 0.03 bbl/day at the start of chemical injection. The improved model is computationally very efficient and is much faster than the fine-grid model.For a practical application, the improved model was used to design and assess the viability of an EOR pilot-test using a single-well, multiple-completion protocol in a fractured carbonate reservoir. This reservoir has a matrix permeability of 10 md and matrix porosity of 0.05, and fracture permeability of 10,000 md. Similar result was obtained using improved and fine-grid models. Also sensitivity analysis was performed on fracture spacing of 5 to 20 ft. We found that smaller matrix blocks are affected more by viscous displacement.

Colloidal Dispersion Gels (CDG's) have been successfully tested in Argentina, China, USA, and recently in Colombia. However, questions remain whether CDG's can be injected in large volumes and propagate deep into the formation without reducing injectivity and also improve sweep efficiency. This paper summarizes 31 implemented and ongoing CDG projects in Argentina, Colombia and the U.S. since 2005. Project summary review includes main reservoir properties, operating conditions, pore volume of chemical injected, general project performance, and especially, a detailed analysis of injection logs addressing the injectivity of CDG. Additionally, a general approach for history matching CDG floods is described. CDG injection volumes in projects reviewed vary from a few thousand barrels to hundreds of thousands of barrels. Projects evaluated did not show injectivity reduction even after more than 600,000 barrels injected in one well. Polymer concentration and polymer: crosslinker ratios ranged from 250 to 1,200 ppm and 20:1 to 80:1, respectively. Aluminum citrate is the most common crosslinker used in field projects. However, chromium triacetate has been used in high salinity and hardness conditions. Key variables to sustain the injection of large volumes of CDG below maximum operating pressure are polymer: crosslinker ratios, polymer concentration, and injection rates to a lesser extent. CDG projects have evolved from small to large treatment volumes showing a positive impact on oil recoveries. Despite large volumes of CDG injected production of polymer in offset producers has rarely been detected. Wellhead pressure response, CDG viscosity, and adsorption/retention (RRF) represents the most important variables needed to match CDG floods. This study provides the status of the technology and field evidence that CDG's can be injected in large volumes and can propagate into the reservoir without injectivity constraints. This review will also provide guidance to successfully design and evaluate CDG pilot projects. Lessons learned from operating and modeling CDG projects will also be presented.

The objectives of this study were to determine the presence and prevalence of non-O157 shiga toxin-producing Escherichia coli (STEC) isolates from faeces of healthy fat-tailed sheep and detection of phylogenetic background and antibiotic resistance profile of isolates. One hundred ninety-two E. coli isolates were recovered from obtained rectal swabs and were confirmed by biochemical tests. Antibiotic resistance profiles of isolates were detected and phylogenetic background of isolates was determined according to the presence of the chuA, yjaA and TspE4.C2 genetic markers. The isolates were examined to determine stx 1 , stx 2 and eae genes. Non-O157 STEC isolates were identified by using O157 specific antiserum. Forty-three isolates (22.40 %) were positive for one of the stx 1 , stx 2 and eae genes, whereas 10.42 % were positive for stx 1 , 19.38 % for eae and 2.60 % for stx 2 gene. None of the positive isolates belonged to O157 serogroup. Twenty isolates possessed stx 1 were distributed in A (six isolates), B1 (13) and D (one) phylogroups, whereas stx 2 positive isolates fell into A (three isolates) and B1 (two) phylogenetic groups. Eighteen isolates contained eae gene belonged to A (five isolates), B1 (seven) and D (six) phylogroups. The maximum and minimum resistance rates were recorded against to penicillin and co-trimoxazole respectively. The positive isolates for stx 1 , stx 2 and eae genes showed several antibiotic resistance patterns, whereas belonged to A, B1 and D phylogroups. In conclusion, faeces of healthy sheep could be considered as the important sources of non-O157 STEC and also multidrug-resistant E. coli isolates.

This paper presents experimental and numerical simulation results of oil recovery from short fractured and unfractured carbonate cores using a high speed centrifuge. The short cores are 1.5-inch in diameter and 1.5-inch long. The experiments are designed to decipher oil recoveries contributions from rock matrix in presence and absence of fractures, with and without surfactant. This research demonstrates that surfactant oil recovery can be a viable enhanced oil recovery process in fractured carbonate reservoirs when fracture distribution and connectivity are favorable. These carefully designed experiments improve our understanding of how oil mobilization can be enhanced in fractured carbonate rocks and how the process can be modeled and solved numerically. Three cores were selected from a Middle East carbonate reservoir, saturated with field brine, displaced with a 9-centipoise field crude, and aged to promote oil-wetness. Three different core designs were used in these experiments. One of the cores was fractured along the vertical axis and sealed with epoxy resin on the outer vertical surface. The second core was fractured and sealed on all outer surfaces except for the fracture opening. The third core was unfractured and sealed on the outer vertical surface. Using a centrifuge, these cores produced 43%, 33% and 42% in waterflood and 40%, 28% and 24% in surfactant flood, respectively. We matched the experimental oil recoveries using two different numerical approaches: a transfer function and a 2-D finite-difference model. The results of these experiments, numerical modeling, and field observations have given us a better understanding of the mechanism of enhanced oil production in fractured carbonate reservoirs by dilute surfactant and micellar solutions. The results of this research are intended to promote field trials.

Many world class large carbonate reservoirs leave behind at least half of the initial oil in place. Typically water injection is used to improve oil recovery while gas injection is used to maintain pressure or to promote oil gravity drainage. Immiscible gas injection, including injection of CO2, has been implemented on a large scale in only few fields for economic reasons. Furthermore, interest in using surfactants in large carbonate reservoirs has recently flourished. As a result, we began to investigate the viability of designing and conducting a manageable pilot test program in a large fractured carbonate reservoir using a single-well, dual-completion system to evaluate the efficacy of the surfactant oil mobilization and oil capture. However, pilot testing in large reservoirs is very expensive and requires a long time to complete. These issues are less problematic in pilot testing of small and thin reservoirs in onshore field. In this paper we present the results of a conceptual model to simulate the performance of surfactant flooding in the above-mentioned pilot test configuration. Three different model formulations, having different approaches to gridding and grid-refinement, were used. These include the dual-porosity, dual-permeability, and conventional variable permeability-porosity formulations to simulate fracture-matrix interactions. Simulation of pilot tests using dual-porosity models shows that gravity is most effective during waterflood but not as effective during the surfactant injection while in the variable permeability-porosity fine-grid model the surfactant oil recovery is greater because both gravity and viscous displacement contribute. We also present a study using our in-house numerical simulator for dual-porosity, dual-porosity refined matrix, dual-porosity with adjustments for viscous displacement and variable permeability-porosity fine-grid models. Dual-porosity models with matrix refinement and viscous displacement give more incremental oil recoveries than the conventional formulation. Results are also compared with variable permeability-porosity fine-grid and coarse-grid models. We will explain the reasons and will indicate which model is more reliable. In general the results of this study give an insight into the viability of using surfactant injection in thick carbonate reservoirs both in the pilot and production stage.