bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overview of CO2 Injection and WAG Sensitivity in SACROC
Authors: Ghahfarokhi Reza Barati , Pennell Steve , Matson Michael , Linroth Mark 
Published: March 2016

Abstract
This paper presents an overview of the SACROC Unit's activity focusing on different CO2 injection and WAG projects that have made the SACROC Unit one of the most successful CO2 injection projects in the world. The main objective of this work was to review CO2 injection and injection rate losses due to the CO2 /WAG miscible displacement process in the SACROC Unit and recommend an injection strategy for WAG-sensitive patterns.
Two types of pattern CO2 /WAG injection rate performance were observed, 1) WAG-sensitive and 2) WAG insensitive. WAG-sensitive patterns displayed loss of CO2 injectivity, exceeding 80% in some patterns, during water-alternating-gas (WAG) injection, and an apparent reduction in water injectivity during the follow-up brine injection. This injectivity loss was observed in over 150 injection patterns. Over time, CO2 injectivity tended to return to prior-to-WAG values. WAG-insensitive patterns suffer from these injectivity losses and were characterized by differences in 1) injectivity profiles, 2) Dykstra-Parsons coefficients, and 3) injectivity indexes.
In the majority of WAG-sensitive patterns, injectivity profiles redistributed after CO2 injection, while WAG-insensitive patterns did not show a significant change in their injectivity profiles over time. In a limited data set, the mean Dykstra-Parsons coefficient calculated for WAG-sensitive patterns was 0.83, while for WAG-insensitive patterns the mean Dykstra-Parsons coefficient was 0.76. However it was observed that in the lower Dykstra-Parsons patterns (WAG-insensitive patterns) much larger injectivity indexes were also observed; 19.5 bbl/day/psi, compared to 8.5 bbl/day/psi for higher Dykstra-Parsons patterns. This suggests that the WAG-insensitive patterns were dominated by fracture flow rather than matrix flow. These observations indicate that the WAG injection process in these heterogeneous SACROC wells is successful in diverting the injected fluids from zones with higher permeability to zones with lower permeability.
For wells with injectivity values of less than 10 bbl/day/psi it is recommended to begin CO2 /WAG injection with a long CO2 cycle since they are likely to show sensitivity to WAG.
A simulated 5-spot pattern was used to study the injection schedule for WAG-sensitive patterns. Longer CO2 cycles and shorter water cycles improved the injectivity and pattern production. Most importantly, it was observed that increasing producing BHP to MMP resulted in significantly lower GOR.
A Comparative Study of the Effect of Gas/Oil IFT Variation on Two- and Three-Phase Relative Permeability and the Performance of WAG Injection at Laboratory Scale
Authors: Jahanbakhsh A. , Sohrabi M. , Fatemi S. M. , Shahverdi H. 
Published: March 2016

Abstract
Gas/oil interfacial tension (IFT) is one of the most important parameters that impact the performance of gas injection in an oil reservoir. The choice or design of the composition of the gas injected for EOR is usually affected by the gas/oil IFT. In conventional reservoir simulation, IFT does not explicitly appear in the equations of flow and therefore its effect must be captured by the shape and values of relative permeability curves. A few studies have been previously reported for IFT effect on two-phase flow but very little have been done to investigate gas/oil IFT effect under three-phase flow conditions. The objective of this study is, firstly, to investigate the impact of gas/oil IFT reduction on two- and three-phase relative permeabilities using coreflood experiments. Secondly, to investigate the effect of changing gas/oil IFT value (immiscible and near-miscible) on the performance of WAG injections and residual oil saturation reduction at laboratory scale.
Two- and three-phase (WAG) coreflood experiments have been performed on water-wet and mixed-wet cores at three different gas/oil IFT conditions. These experiments were conducted on Clashach sandstone cores with a permeability of 65 and 1000 mD. The two- and three-phase relative permeabilities were estimated from the results of the coreflood experiments using our in-house software (3RPSim) and were compared with each other on the basis of their gas/oil IFT values. Moreover, the impact of gas/oil IFT reduction on the performance of gas and WAG injection and in particular on the reduction of residual oil saturation was investigated. The results of our studies were also compared with the existing literature on the laboratory investigation of WAG injection.
The results show that in two-phase gas/oil systems, the relative permeability of non-wetting phase is more affected by a reduction in the gas/oil IFT compared of the relative permeability of the wetting phase. Comparing the curvature of the gas and oil relative permeability curves shows that although the curvature decreases by a reduction in gas/oil IFT but it is still far away from straight line even at ultra-low IFT values. In three-phase flow system, reduction of gas/oil IFT affects the relative permeabilities of all the three phases (gas, oil and water).
The results show that at high gas/oil IFT or immiscible WAG injection, the most reduction in residual oil saturation is achieved in the first injection cycle and further WAG cycles do not result in a significant additional reduction in oil saturation. On the contrary, at low gas/oil IFT or near-miscible WAG injection, the residual oil saturation keeps decreasing as the number of WAG cycles increases. Moreover, the reduction in residual oil saturation was more effective when the immiscible WAG experiments started with gas injection (secondary WAG).
Essentials of Upscaling Surfactants for EOR Field Projects
Authors: Barnes J. R , Regalado D. Perez , Doll M. J. , King T. E. , Pretzer L. E. , Semple T. C. 
Published: March 2016

Abstract
Surfactant flooding is an enhanced oil recovery (EOR) technique that involves the injection of an aqueous solution of surfactant (and, optionally, alkaline and polymer) into an oil reservoir to mobilise and produce the remaining oil. The quantities of surfactants needed for pilots and future commercial scale projects are large (100s to 10,000s of tons) and necessitate large scale manufacture using existing processes and plants for the different manufacturing steps. Upscaling of surfactants requires a rigorous QA/QC process to control and ensure the quality of batches of surfactants produced. Case studies are described from the perspective of a surfactant manufacturer where 800 and 6000 ton of surfactant were manufactured (as 60% and 20% active concentrates respectively) for two multi spot pilots. These case studies illustrate: The need to define the laboratory tests for surfactant composition and performance. Plus associated repeatability data and specifications (minimum and maximum values) for clear, unambiguous decisions.How the QC is checked at each stage in manufacture from the initial feedstock, through various stages, to the final delivered surfactant concentrate/blend. This also applies to the scale-up procedure from the laboratory made scale (kg) to pilot scale (100s of kg) to the pilot/commercial scale (100s to 1000s of tons).Novel correlations between composition and performance (e.g. optimal salinity, via oil/water phase behaviour tests), developed during the surfactant pilot scale manufacture stage, to a) put more emphasis on verifying batch consistency with faster, easier to use composition tests, and b) give more assurance that large scale production gives the expected sub-surface performance. This requires R&D over an extended time, ahead of large scale manufacture.
Overall, the paper shows that industrial scale production of surfactants for chemical EOR is feasible and goes through the essential steps to achieve this. Control of large scale batch quality and performance is critical.
This paper also shows results for improved, highly active (60%+) surfactants concentrates with improved rheology behaviour which will be easier to pump, mix and dilute at the facilities than earlier products. This helps to reduce logistical costs thereby improving project economics.
EOR Potential for Lean Gas Reinjection in Zipper Fracs in Liquid-Rich Basins
Authors: Akinluyi Oluwanifemi , Hazlett Randy 
Published: March 2016

Abstract
Production from liquid-rich shale has become an important contributor to domestic production in the United States, but recovery factors are low. Enhanced Oil Recovery (EOR) methods require injectivity and interwell communication on reasonable time scales. We conduct a feasibility study for the application of recycled lean gas injection to displace reservoir fluids between zipper fracs in liquid-rich shales.
Using new analytical solutions to the Diffusivity equation for arbitrarily-oriented line sources/sinks plus superposition, we analyze the time for inter-fracture communication development, i.e. interference, and productivity index for both classical bi-wing fractures in a zipper configuration and complex fracture networks. We are able to map both pressure and pressure temporal derivative as a function of time and space for production and/or injection from parallel motherbores under the infinite conductivity wellbore and fracture assumption. The infinite conductivity assumption could be later relaxed for more general cases.
We couch the results in terms of geometrical spacing requirement for both horizontal wells and stimulation treatments to achieve reasonable time frames for inter-fracture communication and sweep for parameters typical of various shale plays. We further analyze whether spacing currently considered for primary production is sufficient for direct implementation of EOR or if current practice should be modified with EOR in the field development plan.
An Integrated German MEOR Project, Update: Risk Management and Huff'n Puff Design
Authors: Alkan H. , Klueglein N. , Mahler E. , Kögler F. , Beier K. , Jelinek W. , Herold A. , Hatscher S. , Leonhardt B. 
Published: March 2016

Abstract
This paper provides an update on a microbial enhanced oil recovery (MEOR) project conducted by Wintershall and BASF. Overall nutrient development and planning of a single well field trial (huff'n'puff, HnP) including risk management are described. A nutrient solution is tailored to stimulate growth and metabolite production of a reservoir community of various indigenous microbial species in a Wintershall operated oil field with challenging reservoir characteristics, including high salinity (160,000 ppm). Up-scaled imbibition experiments performed with sandstone cores using MEOR-oil systems are compared with injection brine-oil systems and assessed for the implications on incremental oil. The results of sandpack and coreflood experiments performed with optimized nutrient solutions are discussed regarding incremental oil recovery and responsible EOR mechanisms. A MEOR modelling concept developed using STARS/CMG is used to estimate additional oil production under various feeding strategies after the calibration of the EOR mechanisms assigned.
As the laboratory and numerical works have indicated the feasibility of the MEOR field application, emphasis has been put on risk issues ranked in the register of the project. The key risk is potential souring of the reservoir due to the activation of the sulphate reducing bacteria (SRB) growing on the metabolites generated by the MEOR target community. Conventional mitigation measures have been tested in short and long-term experiments. An innovative solution had been developed to assure H2S free application without any consequences to the reservoir and to the MEOR application.
A single well pilot application is planned in a pre-selected well of the Wintershall field studied with two main objectives: (1) proof of the concept of risk mitigation and (2) stimulation of growth and metabolite production. Identification of operational issues as well as data gathering to improve the forecasting methods towards full-field predictions are secondary objectives. A monitoring plan has been initiated to establish a baseline in terms of microbiological and petro-dynamic parameters. Temperature and volumetric distributions have been predicted based on the results of an injectivity test performed in the well. The data is used to design the HnP operation and the surface setup for the injection rate of 100 m3/day nutrient solution under well-defined conditions.
Polymer-Enhanced Foams for Water Profile Control
Authors: Hernando L. , Bertin H. J. , Omari A. , Dupuis G. , Zaitoun A. 
Published: March 2016

Abstract
Foam injection has been proven to be an efficient technique for EOR applications, stimulation operations and profile control. However, foam is known to have low stability and poor oil tolerance but adding polymer is reported to be an efficient way to improve such foam stability. An extensive study has been undertaken with different surfactants (foaming agents) and polymers to screen out the surfactant/polymer combinations providing the highest foam stability.
We performed a systematic study consisting of static tests (foamability, stability) from which we selected two surfactants (nonionic and anionic) and two polymers (nonionic and associative polymer) expected to highly improve foam performances. Core-flood experiments were performed in high-permeability sandpacks in successive sequences starting with foam propagation, followed by a water flow and then an oil backflow. The Resistance Factor (RF) has been measured for each flow sequence.
Based on our experiments, polymer-enhanced foams is shown to be a promising way for profile control during waterflood and recommendation of use of an associative polymer instead of a classical nonionic polymer is discussed.
Evaluation of Gas Assisted Gravity Drainage GAGD in Naturally Fractured Reservoirs NFR
Authors: Silva R. R. , Maini B. 
Published: March 2016

Abstract
The EOR activity has been very restricted in naturally fractured reservoirs (NFR) because the fluid behavior on these reservoirs are strongly dependent of specific properties of the fractures such as direction, length, thickness, morphology and angle, and good tools were not available to get this information accurately from the reservoirs in the past. Today it is possible to get a lot of information on the fractures by using direct data sources like core samples, drill cuttings and downhole cameras; or even by indirect data sources like well log, well drilling, production history and seismic.
These advancements in the data acquisition have facilitated EOR applications and the EOR activity has increased in the past few years in NFR. GAGD is a promising technique that uses the gravitational flow to improve the sweep efficiency in the reservoir and increase oil recovery. Its benefits have been proven in some academic works and in field applications, such as the Cantarell Oil field that achieved outstanding results.
In this work, we have developed an experimental model that simulates the flow behavior of NFR from a Brazilian offshore oilfield. The model uses rectangular Berea Sandstones blocks that simulate the matrix rock in the experiments and these blocks are separated by small gaps using metal spacers. These gaps act as the fractures in the experimental model. The experimental conditions are close to the reservoir and the used configuration simulates the interaction between matrix and fracture, as well as the flow in the fractures.
In the experiments the blocks are packed in a high-pressure physical model in the desired configuration. The gas is injected from the top and the oil is produced from the bottom. This work investigated the influence of the gas injection rate on oil production. The experiments were history matched using the commercial numerical simulator GEM from CMG.
The experimental results showed good oil recovery performance with recovery factor as high as 40 per cent of OOIP, and it was observed that this value increases when higher gas rates are used. The numerical simulator has some limitations but provided a good history match with the results of the experiments.
This paper proves the efficiency of the CO2 injection in NFR and also presents a new procedure for experimental modeling of fractured systems.
Toward 70% Recovery Factor: Knowledge of Reservoir Characteristics and IOR/EOR Methods from Global Analogs
Authors: Lu Xiaoguang , Sun Shaoqing , Dodds Rich 
Published: March 2016

Abstract
This paper presents the basic reservoir characteristics and the key improved oil recovery/enhanced oil recovery (IOR/EOR) methods for sandstone reservoir fields that have achieved recovery factors toward 70%. The study is based on a global analog knowledge base and associated analytical tools. The knowledge base contains both static (STOIIP, primary and ultimate recovery factors, reservoir/fluid properties, well spacing, drive mechanism, and IOR/EOR methods etc.) and dynamic data (oil rate, water-cut, and GOR, etc.) for more than 730 sandstone oil reservoirs. These reservoirs were subdivided into two groups: heavy and conventional oil reservoirs. This study focuses on the reservoirs with recovery factors great than 50% for heavy oil, and recovery factors from 60% to 79% for conventional oil with a view to understand the key factors for such a high recovery efficiency. These key factors include reservoir and fluid properties, wettability, development strategies and the IOR/EOR methods.
The high ultimate recovery factors for heavy oil reservoirs are attributed to excellent reservoir properties, horizontal well application, high efficiency of cyclic steam stimulating (CSS) and steam flood, and very tight well spacing (P50 value of 4 acres, as close as 0.25 acres) development strategy. The 51 high recovery conventional clastic reservoirs are characterized by favorable reservoir and fluid properties, water-wet or mixed-wet wettability, high net to gross ratio, and strong natural aquifer drive mechanism. Infill drilling and water flood led to an incremental recovery of 20% to 50%. EOR technologies, such as CO2 miscible and polymer flood, led to an incremental recovery of 8% to 15%. Homogeneous sandstone reservoirs with a good lateral correlation can reach 79% final recovery through water flood and adoption of close well spacing.
The lessons learned and best practices from the global analog reservoir knowledge base can be used to identify opportunities for reserve growth of mature fields. With favorable reservoir conditions, it is feasible to move final recovery factor toward 70% through integrating good reservoir management practices with the appropriate IOR/EOR technology.
Modelling Viscosity and Mechanical Degradation of Polyacrylamide Solutions in Porous Media
Authors: Brakstad Kjetil , Rosenkilde Christian 
Published: March 2016

Abstract
A physically based generic viscosity model for synthetic polymer solutions has been created. It gives viscosities as a function of shear rates (Carreau curves). The input to the model is concentration, temperature, salinity and molecular weight (polymer type). A model for mechanical degradation of synthetic polymer solutions has also been developed. It calculates the solution viscosity after mechanical degradation by flow through a porous medium. The two models are linked through molecular weight distributions of the polymer solutions.
The viscosity model fits very well experimental data from viscometry. The mechanical degradation model also fits available experimental data when utilising a correction factor. The models have good predictive power and can be used for different purposes such as, estimating mechanical degradation for different plugging scenarioscalculating the added polymer concentration needed to achieve a given in-situ viscosity at a certain level of degradationcalculating the viscosity degradation for a diluted production fluid with known Mw (from analysis) and unknown concentration.estimating degradation during operation of a well based on the pressure datachoosing the best polymer solution for a specific fieldcalculating the effects of pre-shearing (before injection) and the optimal degree of pre-shearingperform case studies to investigate the impact of system parameters on polymer degradation
The models have also been used for further development to estimate polymer injectivity as well as degradation in process equipment.
Currently, the model predicts slightly increasing degradation for decreasing water salinity which is opposite the trend indicated by most experimental data. Reasons for the deviation are disussed together with suggestions for possible extention of the model.
Success and Lessons Learned from Polymerflooding a Ultra High Temperature and Ultra High Salinity Oil Reservoir - A Case Study from West China
Authors: Wu Xingcai , Yang Zhongjian , Xu Hanbing , Zhang Lihui , Xiong Chunming , Yang Huazhen , Shao Liming , Kang Bo , Fu Yaxiu , Tian Xiaoyan , Cao Huiqing 
Published: March 2016

Abstract
Though polymer flooding is widely considered as a good EOR method for heterogeneous fields, it's always a difficulty to be applied in high temperature and high salinity reservoirs, limited by polymer property. GS-E31 reservoir in West China has ultra-high temperature, 258.8°F (126°C), and ultra-high salinity, 18×104mg/L. It is highly heterogeneous, developed with flowing channels. Starting in July 2012, a new polymer (SMG) flooding was pilot tested, with success technically and economically.
Before SMG injection, tracer test was conducted in the pilot, figuring out the distribution position and direction of prevailing flowing channels. The microscopic pore structure and size were studied. The temperature and salinity resistance of the new particle-type polymer under reservoir condition was tested. The oil displacing effect was simulated on parallel dual core model. For the pilot test, two slugs with different particle sizes were designed. To guarantee the flooding effect, a preposed PPG (preformed particle gel) slug with larger size was designed to inhibit prevailing flow channels.
The lab studies showed the new polymer particles kept stable appearance within 100 days under the reservoir temperature and salinity, denoting high capacity of temperature and salinity resistance. And by physical simulation it could obtain EOR of 12.3%. The pilot test was started in July 2012 and ended in December 2013, and the total liquid injection amount was 12.2×104m3, which was 0.1 PV. During operation, the polymer particle size and concentration were adjusted based on the observing data. As a result, the monthly oil rate of the pilot was increased from 1313 t to 2049.6 t, with increase of 736.6 t; and the water cut was decreased from 91.7% to 84.1%. The cumulative oil incremental was 1.03×104t, and the cumulative water production decrease was 4.79×104m3. The input-output ratio was 1:2.09. Though the economical result was not ideal, it was still acceptable under such severe reservoir conditions. Besides, the surveillance showed the preposed channeling inhibition slug did not perform well, which affected the NPF effect, and especially led to the quick water cut rising in the follow-up water injection phase.
Summarizing the lat studies and pilot tests, the new particle-type polymer has obtained a large breakthrough for temperature and salinity resistance comparing to traditional polymer, and the EOR mechanism is different. The matching relationship between particle size and formation pore size is very important for polymer flooding effect. To further study on lab evaluation method and plan optimization is needed. The technology has important referencing meaning for efficiently developing high temperature and high salinity fields.