bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Field Trial of a Novel, Reservoir-Triggered Polymer: Results, Interpretation and Simulation
Authors: Rashid Bilal , Stapley Jon , Clifford Peter , Chappell David , Kiani Mojtaba , Andrews William J. , Hart Emily C.
Published: March 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.
Modeling CO2 Partitioning at a Carbonate CO2-EOR Site: Permian Basin Field SACROC Unit
Authors: Hosseininoosheri P. , Hosseini S. A. , Nunez-Lopez V. , Lake L. W.
Published: March 2018

The relative partitioning of CO2 during and after CO2 injection in a CO2-EOR process is affected by several parameters. While many geological properties cannot be changed in a specific hydrocarbon (HC) reservoir, it could be shown that an intelligent selection of CO2 injection strategy improves both the incremental oil recovery and CO2 storage capacity and security. Therefore, we investigated and discussed the partitioning of CO2 among different phases (oil, gas, and brine) after two well-known CO2 inejction schemes using field-scale compositional reservoir flow modeling in the SACROC (Scurry Area Canyon Reef Operators Committee) unit, Permian Basin. First, we used a high-resolution geocellular model, which was constructed from wireline logs, seismic surveys, core data, and stratigraphic interpretation. As the initial distribution of fluids plays an important role in CO2 partitioning, a comprehensive pressure-production history matching of primary, secondary, and tertiary recovery was completed. The hysteresis model was used to calculate the amount of CO2 trapped as residual. CO2 solubility into brine was verified based on previous experiments. The model results showed a new understanding of relative CO2 partitioning in porous media after a CO2-EOR process. We compared the contribution of CO2 trapping mechanisms and the sweep efficiency of Walter-Alternating-Gas (WAG) and Continous-Gas-Injection (CGI). We found that WAG injection showed a significantly superior behaviour over CGI. WAG not only decreased the amount of mobile CO2 (structural trapping), but also resulted in a competitive incremental oil recovery in comparison with CGI. Thus, clearly WAG injection ispreferred as it strongly enhances CO2 storage efficiency and containment security. The present work provides valuable insights for optimizing oil production and CO2 storage in carbonate reservoirs like SACROC unit. In other words, this work helps decision makers to set storage goals based on optimized project risks.
Gas and Downhole Water Sink-Assisted Gravity Drainage GDWS-AGD EOR Process: Field-Scale Evaluation and Recovery Optimization
Authors: Al-Mudhafar Watheq J. , Wojtanowicz Andrew K. , Rao Dandina N.
Published: March 2018

The Gas and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process has been developed to overcome of the limitations of Gas flooding processes in reservoir with strong aquifers. These limitations include high levels of water cut and high tendency of water coning. The GDWS-AGD process minimizes the water cut in oil production wells, improve gas injectivity, and further enhance the recovery of bypassed oil, especially in reservoirs with strong water coning tendencies.

The GDWS-AGD process conceptually states installing two 7 inch production casings bi-laterally and completing by two 2-3/8 inch horizontal tubings: oil producer above the oil-water contact (OWC) and one underneath OWC for water sink drainage. The two completions are hydraulically isolated by a packer inside the casing. The water sink completion is produced with a submersible pump that prevents the water from breaking through the oil column and getting into the horizontal oil-producing perforations.

The GDWS-AGD process was evaluated to enhance oil recovery in the heterogeneous upper sandstone pay in South Rumaila Oil field, which has an infinite active aquifer with a huge edge water drive. A compositional reservoir flow model was adopted for the CO2 flooding simulation and optimization of the GDWS-AGD process. Design of Experiments (DoE) and proxy metamodeling were integrated to determine the optimal operational decision parameters that affect the GDWS-AGD process performance: maximum injection rate and pressure in injection wells, maximum oil rate and minimum bottom hole pressure in production wells, and maximum water rates and minimum bottom hole pressure in the water sink wells. More specifically, Latin hypercube sampling and radial basis neural networks were used for the optimization of the GDWS-AGD process performance and to build the proxy model, respectively.

In the GDWS-AGD process results, the water cut and coning tendency were significantly reduced along with the reservoir pressure. That resulted to improve gas injectivity and increase oil recovery. Further improvement in oil recovery was achieved by the DoE optimization after determining the optimal set of operational decision factors that constrains the oil and water production with gas injection. The advantage of GDWS-AGD process comes from its potential feasibility to enhance oil recovery while reducing water coning, water cut, and improving gas injectivity. That gives another privilege for the GDWSAGD process to reach significant improvement in oil recovery in comparison to other gas injection processes, such as the Gas-Assisted Gravity Drainage (GAGD) process, particularly in reservoirs with strong water aquifers.
A Successful Polymer Flood Pilot at Palogrande-Cebu, A Low Permeability Reservoir in the Upper Magdalena Valley, Colombia
Authors: Leon J. M. , Castillo A. F. , Perez R. , Jimenez J. A. , Izadi M. , Mendez A. , Castillo O. P. , Londoño F. W. , Zapata J. F. , Chaparro C. H.
Published: March 2018

Palogrande-Cebu is a mature clastic field located in the south of Colombia and part of the production train of the Monserrate Formation that has several fields and presents an OOIP about 1000 MMBBLs. In these fields Ecopetrol have been tested different chemical EOR/IOR technologies like polymer flooding, CDG and conformance treatments with encouraging results. Palogrande field has been in production since 1971, and under peripheral water injection since 1984, with a recovery factor of 28%. The reservoir has a permeability between 6 and 150 mD, and a crude with an in-situ viscosity of 9.4 cP at reservoir conditions. As part of a portfolio screening within Ecopetrol, chemical EOR was considered the most viable option for the field. This lead to a polymer flood pilot in Palogrande-Cebu in two patterns from May 2015 to June 2017.

The present paper presents the results of the pilot, which includes the assessment of two different sources of water to prepare the polymeric solution, fresh water and produced water. Likewise, three different polymers were used to assess the impact on injectivity of the molecular weight considering the low permeability of the reservoir. Moreover, the paper presents the data from a comprehensive surveillance and monitoring program, which includes a polymer backflow test to assess the polymer viscosity in the reservoir.

As of June 2017 the accumulated polymer injection was 2.07 million barrels distributed between both injectors, and a projected incremental recovery factor of 8% in the most mature pattern, and 2% in the less mature pattern, with water cut reductions up to 14% in some wells. Based on the success of the pilot, the feasibility of expanding the polymer flood is currently being considered to further develop the field.
Boosting Oil Recovery in Unconventional Resources Utilizing Wettability Altering Agents: Successful Translation from Laboratory to Field
Authors: Kazempour Mahdi , Kiani Mojtaba , Nguyen Duy , Salehi Mehdi , Bidhendi Mehrnoosh Moradi , Lantz Mike
Published: March 2018

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.
Fluoroacrylate Polymers as CO2-soluble Conformance Control Agents
Authors: Enick Robert M. , Lee Jason J. , Cummings Stephen D. , Zaberi Husain A. , Beckman Eric J. , Dailey Chris , Vasilache Mihai
Published: March 2018

In this study, we propose a CO2-polymer solution for conformance control agent in order to divert the subsequently injected CO2 away from thief zones and toward lower permeability oil-rich zones. A novel CO2-soluble polyfluoroacrylate (PFA) was synthesized. PFA is an amorphous, sticky, transparent, homopolymer that dissolves readily in CO2 at temperatures and pressures commensurate with CO2 EOR. PFA is based on a monomer that contains six (rather than eight) fluorinated carbons, thereby eliminating the environmental concerns associated with possible degradation products. Because PFA has high molecular weight, the addition of ~1wt% PFA to CO2 thickened CO2 by a factor of about four. Nnumerous core floods were then conducted to determine if the adsorption of PFA onto the rock surfaces could provide conformance control. When a CO2-PFA solution is injected into porous media, a portion of the dissolved PFA strongly adsorbs onto the mineral surfaces, regardless of what fluid was originally present in the pores. Because PFA is highly hydrophobic and oil-phobic, the thin PFA film deposited on the rock surfaces changes the wettability and dramatically reduces the permeability of the rock (especially sandstone) for subsequently injected fluids. This strong adsorption and change in wettability significantly reduces the permeability of the rock to subsequently injected brine or CO2. Dual parallel core floods were conducted to demonstrate the efficacy of PFA-CO2 solutions for conformance control. Excellent results were obtained when a CO2-PFA solution was injected solely into an isolated high permeability (80 mD) Berea sandstone core (the thief zone) that was previously flooded with brine and CO2. After this treatment, the Berea core was then placed in parallel with a 20 mD Carbon Tan sandstone core. All of the subsequently injected CO2 was diverted to the Carbon Tan core. Similar results were obtained with dual parallel limestone cores. To the best of our knowledge, PFA is the first known example of a CO2-soluble polymeric conformance control agent.
Evaluation of Viscosity Loss of Viscosified Brine Solutions Due to Shear Degradation in Distribution System Components
Authors: Theriot Timothy P. , Linnemeyer Harold , Alexis Dennis , Malik Taimur , Perdue Charles
Published: March 2018

High molecular weight HPAM's tend to be highly shear sensitive. Various components of polymer mixing and distribution systems pose risk to the integrity of HPAMs due to high shear experienced at valves, chokes and other flow control devices. At a minimum, this risk can severely impact chemical EOR operating cost due to polymer degradation and consequential viscosity loss of the injectate. Low-shear, low-cost polymer injection distribution systems have the potential to reduce polymer usage, maintain injection stream viscosity, and enable integration into brownfield facilities. Lower viscosity losses translate into optimized operating and capital cost for CEOR pilot and full field projects. The objective of this work was to determine the equipment (piping), process, and polymer parameters that affect viscosity loss due to shear degradation.

In this work, polymers were evaluated from two different vendors. The effects of molecular weight, chemical concentration, and brine salinity on polymer sensitivity to viscosity loss due to shear degradation were investigated. Polymer solutions were either blended on site or purchased pre-blended in synthetic brine solutions. Pumped by a positive displacement, low-shear pump, the solutions flowed through a mass meter and were delivered to a distribution system component at various flow rates. For flow control devices, pressure differentials were adjusted at fixed flow rates. Polymer solution samples were collected upstream and downstream of the tested component. Samples were taken in no-shear sample collectors. Pressure upstream and downstream of the test component and flow rate were recorded during the flow test. Viscosity was measured with a Brookfield viscometer at ambient temperature. When higher concentration solutions were tested, viscosity was measured of diluted samples at target concentration to determine amount of shear degradation as evidenced by viscosity loss.

Results indicate that viscosity degradation of polymer solutions does occur in flow control devices and is directly correlated to pressure differential across the pipe device. Internal geometry has little impact on the amount of degradation. Velocity has little impact on the amount of degradation. Polymer molecular weight and structure both affect the amount of degradation due to shear as does solution concentration. Generally, viscosified brine solutions will lose viscosity when flowed through devices with greater than 50 psi differential pressure in the range of 15-50% of initial viscosity. Using more concentrated polymer streams and diluting to target concentration after flow control will reduce the amount of viscosity loss.

Based on the laboratory results, design and operating condition, recommendations can be made for polymer injection distribution systems to minimize shear degradation of the flowing viscosified brine stream.
Improving CO2 Foam for EOR Applications Using Polyelectrolyte Complex Nanoparticles Tolerant of High Salinity Produced Water
Authors: Nazari Negar , Tsau Jyung-Syung , Barati Reza
Published: March 2018

Although surfactant generated CO2 foam improves the mobility control for CO2 flooding, it suffers from instability in the presence of crude oil and in high salinity environments. The objective of this work is to improve the stability of the interface by lowering surfactant drainage and improving the stability of lamellae in high salinity produced water using polyelectrolyte complex nanoparticles and generate a more stable foam front in the presence of crude oil. This results in improving the recovery efficiency of foam floods.

In this project, an optimized system of polyelectrolyte complex nanoparticles was used to improve scCO2 foams prepared in high salinity produced water. The effect of nanoparticles on the interfacial properties of the foam was studied. Thereafter, a set of core flooding experiments with and without the crude oil in the system was conducted to measure the apparent viscosity and the incremental oil recovery due to addition of polyelectrolyte and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam in high salinity produced water.

Studying the interfacial properties of different foam systems shows that addition of polyelectrolytes and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam improves the elasticity of the interface. Furthermore, adding polyelectrolytes and polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam, improves the efficiency of the oil recovery by improving the apparent viscosity and making the foam more stable in the presence of crude oil. Polyelectrolyte complex nanoparticles produced incremental oil when the surfactant foam system reached its residual oil and produced no more oil.

Generating a very stable system of the foam by adding polyelectrolyte complex nanoparticles to the surfactant generated CO2 foam prepared in high salinity produced water, results in a longer lasting foam and increase the incremental oil recovery up to 10%. The sea water salinity is applicable for all the locations with access to the sea water as well as locations with produced water salinities close to sea water. The higher salinity system covers a wide range of the reservoirs in the United States and worldwide with access to produced water.
Exploring the Upper Limit of Oil Viscosity for Polymer Flood in Heavy Oil
Authors: Delamaide Eric
Published: March 2018

Large scale polymer flooding projects in heavy oil are now ongoing in several countries and numerous other projects are at the pilot or design stages. However, there is currently no guideline for the maximum acceptable oil viscosity, one of the important parameters in the screening of new projects. Standard screening criteria do not take the latest field results into account and more recent guidelines rely mostly on viscosity averages whereas they should focus on the extreme values instead.

Since the laboratory can only provide little help to settle this issue we propose to examine current field projects for guidance.

To the best of the author's knowledge, the Pelican Lake and the Seal polymer floods, both in Canada, are operating in the highest oil viscosity ranges; moreover, the data is public and can easily be accessed. We have therefore examined the performances of polymer injection in the highest ranges of oil viscosity in both fields to get an understanding of the limits. This involved first the identification of the highest oil viscosity patterns, then the estimation of the live oil viscosity during the polymer flood in these patterns and finally the performances of the polymer flood.

Viscosity measurements are notoriously difficult and not always very reliable in heavy oil and the evaluation of in-situ viscosity is even more difficult; therefore, we used ranges of viscosity rather than definite values. The observations from Pelican Lake and Seal seem in good agreement and suggest that polymer flood is still feasible and can provide an acceleration in production for live oil viscosities up to 10,000-12,000 cp. There is little experience beyond these values, but it appears that for higher ranges of viscosity polymer injection becomes much more difficult; in Seal polymer flood does not appear to be working satisfactorily in oil viscosities above 14,000 cp.

To the best of the author's knowledge, this is the first time that the issue of maximum oil viscosity is investigated in such a manner. Although these results are preliminary and would require further confirmation from other field cases, this paper will provide guidance to engineers screening heavy oil reservoirs for potential application of polymer flood.
Multi-Well Analytical Solution for Coning Under Simultaneous Steady-State Flow of Three Phases
Authors: Ahn Eunnam , Johns Russell T. , Phaiboonpalayoi Chonpatin
Published: March 2018

Unwanted water or gas production from upward or downward coning can significantly erode profits in oil recovery processes. Simulation estimates of the magnitude and timing of coning can be erroneous owing to unknown reservoir heterogeneity, large grid blocks near the wells, and inaccuracies in simulation well models, such as that from Peaceman.

This paper presents a multi-well steady-state analytical solution for coning of three phases (water, oil, and gas) flowing simultaneously. The solution for multiple wells is developed using superposition with a coning potential function that includes capillary pressure and relative permeability. The assumption of vertical equilibrium (VE) is made, which gives maximum crossflow vertically and therefore the largest possible coning. Any model for relative permeability and capillary pressure can be used, although we used Stone 2 for relative permeability and Brooks-Corey for capillary pressure. We give dimensionless inflow performance windows (IPW) to show the allowable physical window of three-phase rates and the maximum oil rate as a function of the water and the total well flow rate. The new potential functions are also used to demonstrate superposition for several well patterns with no-flow boundaries. Besides estimating critical oil rates, the solution could be important to benchmark numerical solutions and improve the accuracy of Peaceman's well model.
Sulfonated Polyacrylamides - Evaluation of Long Term Stability by Accelerated Aging at Elevated Temperature
Authors: Nurmi Leena , Sandengen Kristian , Hanski Sirkku , Molesworth Peter
Published: March 2018

When EOR by polymer flooding is applied in the offshore environment, polymer can be expected to face long reservoir retention times of up to several years. The stability and viscosity retention of the polymer needs to be evaluated throughout this time. Copolymers of acrylamide (AM) and acrylamide tertiary butyl sulfonic acid (ATBS) are a potential polymer choice for relatively high temperature and salinity reservoirs. In this study, it was evaluated how the long term stability of AM-ATBS copolymers can be predicted by accelerated aging tests at elevated temperature.

The main cause of viscosity loss in AM-ATBS copolymer solutions is the hydrolysis reaction turning AM and ATBS groups into acrylic acid (AA). This hydrolysis was studied in strictly anaerobic conditions at 70-120°C. Besides temperature, the impact of ATBS content in the copolymer (15-55 mol%), pH, salinity and divalent ion concentration were studied. In addition, some tests were done with copolymers of ATBS and AA to elucidate the effect of neighboring monomer on ATBS hydrolysis. The reaction progress was followed by 13C NMR and viscosity measurements.

Over a range of conditions, it was observed that AM-ATBS copolymers aged at different temperatures but at otherwise equal conditions, had similar AA/AM/ATBS ratios at equivalent degrees of hydrolysis. Additionally, the shapes of viscosity retention vs. time curves were corresponding in the studied temperature interval after being normalized into the same time scale. It is proposed that AM hydrolysis is the rate determining step, resulting in a similar hydrolysis pathway over a range of temperatures. AM hydrolysis reaction rates were fitted into an Arrhenius function to estimate acceleration at elevated temperatures.

The data generated in this study helps to predict how the results from accelerated tests (e.g. at 100-120°C) correlate to stabilities at lower temperature (e.g. actual reservoir temperature at 70-80°C). Specifically, a practical overview of expected time of stability (viscosity retention >80%) has been generated for AM-ATBS copolymers in seawater.
Nuclear Magnetic Resonance Study on Oil Mobilization in the Shale Exposed to CO2
Authors: Wang Haitao , Lun Zengmin , Lv Chengyuan , Lang Dongjiang , Luo Ming , Zhao Qingmin , Zhao Chunpeng
Published: March 2018

The reservoirs in Qian 34 10 rhythmic layer of Qianjiang Basin were shale oil with intersalt sediments. During natural depletion development process production rapidly decreased. Water injection and CO2 injection were considered as potential technology for shale oil EOR. Due to high salt content of shale rock and dissolution of salt in water, water injection damaged the reservoirs. CO2 injection didn't react with salt to damage the reservoirs. Meanwhile, CO2 could enter micro pores of reservoir rock and mobilize oil by the mechanisms of diffusion, extraction and swelling and so on. In order to verify oil mobilization in shale exposed to CO2 exposure experiments based on nuclear magnetic resonance (NMR) were conducted in this study.

NMR T2 spectrum can measure the oil signal and determine the oil content of rock with low permeability. In this study 10 fresh shale samples (from 6 depths) were measured and oil contents were determined using NMR T2 spectrum. Two shales with higher oil content were selected and performed exposure experiment. Under the temperature of 40 °C and the pressure of 17.5 MPa fresh shale was exposed to CO2 and NMR T2 spectrum was used to measure the oil content of shale continuously. Oil mobilization in shale exposed to CO2 was determined.

The results of NMR T2 spectrum showed that NMR signals of 9 fresh shale samples were good and oil contents of fresh shales were high. Recovery of S5# shale exposed to CO2 was 51.2% after 8 days. Recovery of S9# shale exposed to CO2 was 55.8% after 6.1 days. These results indicated that more than half of shale oil were mobilized with relative long exposed time during CO2 injection. The results of NMR T2 spectrum showed that oil in all pores could be mobilized as exposure time increased.

This study showed the quantitative results for CO2 injection and EOR in shale oil of Qianjiang Basin. All conclusions provided confidence to start CO2 EOR pilot project in shale oil with intersalt sediments with ultra-low permeability.
Application of Multi-Well Steam Injection and CO2 Technology in Heavy Oil Production, Liaohe Oilfield
Authors: Jin Fu , Xi Wang , Shunyuan Zhang , Bingshan Liu , Chen Chen
Published: March 2018

Liaohe Oilfield is well-known for wide distribution of heavy oil resoures whose viscosity is around 6.2×104mPa·s (degassed crude oil at 45°C). Heavy oil resources are usually found at the depth of 500-1700m. An integrated research has been completed to study the most efficient utilization of steam huff and puff methodology.

In order to compare the new steam injection method with the conventional EOR method, we selected 7 wells in which steam injection was simulated by software. The high temperature gel particle plugging agents, high temperature frothers and resins were tested. The overall sweep efficiency and oil production rate of these wells were compared with that of adjacent wells that depended on conventional steam injection methodologies.

The multi-well steam injection requires injecting steam into a specific group of wells, so that an overall thermal field may be created. In this way, steam channeling caused by longitudinal heterogeneity of heavy oil reservoirs may be overcome. CO2 has the best role in reducing the oil viscosity, while natural gas and nitrogen follow it. So CO2 is the most appropriate EOR gas. CO2's dissolubility declines as temperature goes up and improves as pressure increases. Temperature of liquefied CO2 varies a lot with different injection speeds, in that the heat diffusion time is different. The faster CO2 is injected, the shorter the heat diffusion time is, which makes downhole temperature change less. As CO2 is injected into formation, it dissolves rapidly with heavy oil and makes it expand. Steam is injected then to heat the borehole, while CO2 diffuses rapidly and its dissolubility declines as temperature goes up, which makes CO2 separated from oil and diffused by scale. Thus, clean-up additives and steam are widely distributed. After shut-in CO2 spreads until it keeps balanced dynamically with viscosity reducers.

The daily production rate used to start to decrease after 5 rounds of steam injection. By injecting steam and CO2 into a group of wells we succeeded in improving the sweep efficiency and production rate.
In Situ Carbon Dioxide Generation for Improved Recovery: Part II. Concentrated Urea Solutions
Authors: Wang Shuoshi , Yuan Qingwang , Kadhum Mohannad , Chen Changlong , Yuan Na , Shiau Bor-Jier , Harwell Jeffrey H.
Published: March 2018

While injection of CO2 has great potential for increasing oil production, this potential is limited by site conditions and operational constraints such as lack of proper infrastructure, limited cheap CO2 sources, viscous fingering, gravity override at the targeted zones, and so forth. To mitigate some of these common limitations, we explore alternative methodologies which can successfully deliver CO2 through gas generation in situ, with superior IOR performance, while offering reasonable chemical cost.

While dissolved easily in reservoir brine, urea is thermally hydrolyzed to CO2 and NH3 after equilibration under reservoir conditions. Therefore, given its exceptional compatibility with reservoir fluids, its CO2 producing capacity and reasonable cost benefit, urea appears to be a promising candidate for delivering CO2 to increase oil recovery. The in-situ gas generation requires single chemical slug, which can minimize the complexity of the injection system.

One-dimensional sand pack tests and core flooding experiments were operated at pre-set conditions: different API gravity oils were used, varying from 27 to 57.3. In addition, the reaction rates of the urea hydrolysis and urea solution PVT property were tested separately under reservoir conditions.

Most importantly, results of injecting urea solution (as low as 10 % solution) showed superior tertiary recovery performance (as high as 37.97%) are realized as compared to the most recent efforts at our group (29.5%) as well as similar in situ CO2 generation EOR (2.4% to 18.8%) approaches proposed by others.

The economic feasibility and operational advantages of this newly developed method were demonstrated in this work. In brief, results of this work served further as a proof of concept for designing in situ CO2 generation formulations for tertiary oil recovery at both onshore and offshore fields under proper conditions.
Polymer Oil Recovery Experiments in Different Geometries for Improved Upscaling of Viscous Oil Reservoirs
Authors: Lee Vincent , Doorwar Shashvat , Dwarakanath Varadarajan , Isbell J. Taylor , Malik Taimur , Slaughter Will
Published: March 2018

Upscaling the simulation of unstable displacement of heavy oil is challenging because accurately modeling the development and propagation of viscous instabilities within a simulation grid-block is next to impossible. Various models have been developed that are capable of history matching oil recovery results, however, there is little lab data to allow for validated scale-up of these viscous fingering model. We present experimental results from different geometries, i.e. cylindrical corefloods, 2D slabs and 3D blocks, where a viscous oil is displaced by water and polymer solutions, under pressure-constrained injection.

Waterflood and polymer flood oil recovery experiments were performed in ‘2-Dimensional’ (2D) sandstone slabs (12" by 12" by 1") and ‘3-Dimensional’ (3D) blocks (12" by 12" by 4") of sandstone and compared with oil recovery experiments through linear ‘1-Dimensional’ (1D) cylindrical cores. Experiments were performed with a high viscosity (540 cP) mineral oil at room temperature. UTCHEM (a software product from The University of Texas at Austin) with viscous fingering model was used to model the experiments and identify parameters for scaling the process to a field scale.

As expected, water breakthrough was accelerated as we moved from cylindrical cores to 2D slabs to 3D blocks. For the experiments conducted, gravity instability had a minimal effect compared to viscosity instability, even for the 3D blocks. Pseudo relative permeability curves based on the modified viscous fingering model were developed to match the 1D experiment. The same pseudo parameters showed excellent scalability across the varying experimental geometries (1D, 2D and 3D). These results indicated that the effective finger width did not vary for the different geometries.
EOR Potential in the Post Steam Injection Era: Current and Future Trends
Authors: Dong Xiaohu , Liu Huiqing , Wu Keliu , Chen Zhangxin
Published: March 2018

The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China.

This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.
Modeling of CoSolvent Assisted Chemical Flooding for Enhanced Oil Recovery in Heavy Oil Reservoirs
Authors: Dang Cuong , Nghiem Long , Nguyen Ngoc , Yang Chaodong , Mirzabozorg Arash , Li Heng , Chen Zhangxin
Published: March 2018

Many attempts have been made to understand, design, and optimize a chemical flooding process; however, the current low oil price environment makes its implementation very challenging from an economics point of view. Recently, CoSolvent Assisted Chemical Flooding (CACF) has been considered as a promising approach to reduce the cost of surfactant-based recovery methods, especially in heavy oil reservoirs. More importantly, recent studies indicated that CACF can be efficiently applied at relatively low temperature, i.e., without the need of steam injection. This helps reduce for the cost of steam generation and injection, and the associated greenhouse gas effects. This paper presents a new development in modeling CACF using an Equation-of-State (EOS) compositional reservoir simulator.

We used a new approach to model the behavior of the oil-water-microemulsion system based on solubility data without modeling type III microemulsion explicitly. The results showed an excellent agreement with numerous chemical coreflooding data and are in agreement with a chemical floodingresearch simulator. The new development presented includes the effects of cosolvent on rheological properties and phase behavior of microemulsion in the CACF process, particularly microemulsion viscosity and interfacial tension.

The proposed model showed good agreement with four published CACF coreflood experiments in which surfactant was not used in alkali and polymer chemical slugs. This model efficiently captures the complex chemical reactionsoccurring in the CACF process, i.e., generation of in-situ soap based on reactions between alkali and a rich acid component in heavy crude oil. The model provides consistent results with laboratory coreflood data at different operating temperatures, which is very important for heavy oil reservoirs. The ultimate recovery factor by CACF coreflooding is about 97%, similar to ASP (Alkali, Surfactant and Polymer) coreflooding, but without the need of surfactant injection.
A New Thermally Stable Synthetic Polymer for Harsh Conditions of Middle East Reservoirs: Part II. NMR and Size Exclusion Chromatography to Assess Chemical and Structural Changes During Thermal Stability Tests
Authors: Rodriguez L. , Antignard S. , Giovannetti B. , Dupuis G. , Gaillard N. , Jouenne S. , Bourdarot G. , Morel D. , Zaitoun A. , Grassl B.
Published: March 2018

Most Middle East fieds present harsh reservoir conditions (high temperature, high salinity, low permeability carbonates) for polymers used as EOR mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable. At temperatures above 60°C, acrylamide moieties hydrolyze to sodium acrylate which ultimately leads to precipitation and total viscosity loss. Thermal stability can be improved by incorporating monomers such as ATBS or NVP.

In a previous paper, we reported the development of terpolymers where incorporation of NVP was shown to provide improved stability up to 120°C. Unfortunately, NVP increases the cost of the polymer and limits its molecular weight. Additionally, NVP also causes drifts in the polymers composition, thereby impairing injectivity in low permeability carbonate rocks. The price of the final product, to achieve a given viscosity, is approximately 3 times higher compared to conventional HPAM polymers and 2 to 2.5 times higher than SPAM polymers (sulfonated polyacrylamide). More recently, we reported the synthesis of NVP-free polymers incorporating different mol precentages of ATBS. The ATBS containing polymers are cheaper than the NVP polymers and enable dosage reductions of up to 50%, to obtain the same viscosity. Additionally, they outperformed the NVP polymers in terms of injectivity and thermal stability, as well as pushed the stability limits from 105-110°C up to 130°C and 140°C in brines withTDS of 230 g/L and 100 g/L respectively.

In this study, we present new data for viscosity and thermal stability of NVP-free polymers optimized in terms of process and molecular weight. In particular, the thermal stability study was completed with NMR spectroscopy and Size Exclusion Chromatography (SEC) analysis to obtain information on the evolution of the chemistry and the molecular weight distribution of the polymers during long-term aging. NMR and SEC analysis reveal that the reduction of the viscosity during aging is due to an evolution of the polymer chemistry (conversion of acrylamide and ATBS units in acrylates) as well as chain scission. The incorporation of ATBS, into the polymer backbone, appears to slow down hydrolysis and limits the viscosity loss. There was no modification of the chemistry observed for the polymer having the highest level of ATBS and any viscosity loss observed is directly related to a decrease in molecular weight.

The optimization of the NVP-free polymers redues the dosage by one third, making them very attractive from an economic standpoint. Both NMR and SEC techniques, have been shown to be efficient tools to understand the mechanism involved in viscosity changes for polymer solutions during long-term thermal aging.
Understanding the Oil Recovery Mechanism in Mixed-Wet Unconventional Reservoirs: Uniqueness and Challenges of Developing Chemical Formulations
Authors: B. Alamdari Baharak , Hsu Tzu-Ping , Nguyen Duy , Kiani Mojtaba , Salehi Mehdi
Published: March 2018

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.
An Integrated CO2 Foam EOR Pilot Program with Combined CCUS in an Onshore Texas Heterogeneous Carbonate Field
Authors: Alcorn Z. P. , Fredriksen S. B. , Sharma M. , Rognmo A. U. , Føyen T. L. , Fernø M. A. , Graue A.
Published: March 2018

A CO2 foam enhanced oil recovery (EOR) field pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results due to injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a more integrated multiscale methodology is required for project design to further understand the connection between laboratory and field scale displacement mechanisms. Foam is frequently generated in a reservoir through the injection of alternating slugs of surfactant solution and gas (SAG). To reduce costs and increase the success of in-situ foam generation, SAG operations must be optimized for field implementation. This study presents an integrated upscaling approach for designing a CO2 foam field trial, including pilot well selection criteria, comprehensive laboratory coreflood experiments combined with reservoir scale simulation to offer recommendations for a SAG injection schedule while assessing CO2 storage potential.

Laboratory investigations include dynamic aging, foam stability scans, CO2 foam EOR corefloods with associated CO2 storage, and unsteady state CO2/water endpoint relative permeability measurements. Wettability tests of restored reservoir core material yield Amott-Harvey index values of −0.04 and −0.79, indicating weakly oil wet to oil wet conditions. Foam scans demonstrate highest foam quality at gas fraction (fg) of 0.70. CO2 foam EOR corefloods after completed waterfloods, at optimal foam quality, result in a total recovery factor of 80% OOIP with an incremental recovery of 35% OOIP by CO2 foam.

A negligible difference is observed in incremental CO2 foam recoveries and apparent viscosities when using 1 wt% and 0.5wt% surfactant solution. High differential pressures during CO2 foam suggest generation of stable foam with mobility reduction factors by CO2 foam up to 340, over CO2 at reservoir conditions. CO2 storage potential was assessed during displacement to investigate the carbon footprint of CO2 foam injection.

Relative permeability endpoints and foam stability scan parameters are input into a validated field scale numerical simulation model to recommend design parameters for SAG injection. The numerical model investigates foam's impacts on oil recovery, gas mobility reduction, producing gas oil ratio (GOR), and CO2 utilization. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.