Wu, Xingcai (Research Inst. of Petroleum E&D CNPC) | Wu, Hongbiao (Exploration and Production Company,CNPC) | Bu, Zhongyu (Exploration and Production Company,CNPC) | Bai, Lei (Xinjiang Oilfield Company, CNPC) | Zhang, Song (RIPED) | Yu, Zhentao (RIPED) | Xu, Hanbing (RIPED) | Zeng, Qingqiao (Huabei Oilfield Company, CNPC) | Jiang, Yuzhu (Startwell Energy Co. Ltd)
XJ6 is a conglomerate reservoir, with oil viscosity 80mPa.s. The reservoir is quite heterogeneous, and seriously uneven sweeping exists. For exploring high efficiency EOR method, three types of EOR models were designed, utilizing continuous phase crosslinked polymer gel (LPG), nano-micro grade particle type polymer SMG dispersion, and millimeter grade pregelled swellable particle (SLG). And field comparison tests were conducted.
In field tests, the chemical slug injection started in April 2013 and ended in January 2015. The injection liquid amount was 0.2PV. Model 1 features preset plugging slug of LPG carried SLG and the following oil displacing slug of LPG slugs with different viscosity, and the pilot consists of 25 injectors and 42 producers. Model 2 features preset plugging slug of LPG carried SLG and the following 4 times of alternate injection of SMG slug and small LPG slug, and SMG dispersion is the main slug in the model. Model 3 features three times of alternate injection of water and high viscosity LPG combined with SLG slug.
Model 1 and Model 2 obtained obvious effect quickly. For Model 1, due to continuous injection of viscous fluid, both of oil flowing resistance and water flowing resistance greatly increased, leading to low liquid supplying capacity for the producers, so the effect of oil increasing and water cut decreasing could not be further improved or sustained for a long period. For Model 2, the small slugs of SLG and LPG pluged or inhibited the macroscopic and midscopic scales of prevailing flowing, and the main slug of low apparent viscosity SMG dispersion was used to deal with the microscopic scale uneven sweep, in which, with the SMG particles temperarilly inhibiting the big pores or high permeability area, the water was diverted into small pores or low permeability area to efficiently displace the relatively high saturated remaining oil there. So Model 2 obtained better effect of oil increasing and water cut decreasing. During chemical injection in Model 2, the daily oil rate increased by 2.9 times, and that of Model 1 is 1.1 times. And the maximum water cut decrease of Model 1 and Model 2 was 32.2 and 46.2 percent respectively. Model 3 did not show obvious EOR effect.
The field comparison tests verified the advancement of Model 2, which features multi-grade diversion and displacement, and the scientific nature of syncronouse diversion and displacement mechanism. It also obtained economical success. Therefore, for waterflooded reservoir with complex pore structure and high heterogeneity, the multi-grade divertion and displacement technology can be used to greatly improve utilizing efficiency of the injected water, achiving the aim of oil recovery enhancement.
Encouraging results from Lab, simulation studies and single well pilot tests (SWCT tests) using ASP flooding provided confidence to conduct multi well pilot test. A confined, normal 5-spot pattern CEOR pilot is planned. SAMA performance over its waterflood life of 17 years has highlighted reservoir heterogeneity in terms of rock and fluids. The paper describes activities performed during pre-pilot phase of drilling 7 pilot wells to de-risk the complexities expected in this carbonate reservoir.
Drilling of 7 close spacing vertical well within 5 acre required proper planning and drilling sequence. Out of the seven wells, four corner wells are drilled as injectors and center well as producer. Two observation wells within the pilot area include a sampling well and the other completed with fiberglass casing as a logging well. Data acquisition from coring, formation pressure measurement, sampling, H2S measurement and logging is meticulously planned and quality checked.
The main objective of this CEOR pilot is to field test the efficacy of the ASP formulation prepared in the lab. This pilot scale testing would help a better risk assessment and estimate of incremental oil gain due to this technology application. Field-wide implementation of this technology in Sabiriyah Mauddud and other reservoirs in NK will depend on the success of this CEOR Pilot. All 7 EOR pilot wells were successfully drilled despite many challenges using industry’s best practices. Enormous good quality data was generated during drilling of these wells which will aid in understanding the complexity of reservoir within small pilot area and help in implementation of Chemical EOR in Sabiriyah Mauddud reservoir. All the information generated during pre-pilot will be utilized for starting up this CEOR pilot.
EOR in carbonate reservoir has been a challenge for the oil industry. These challenges and related risks are mostly attributed to the complexity of reservoir description. Good quality wells and exhaustive information generated during pre-pilot phase did provide valuable insights to de-risk and ensure proper implementation of the Chemical EOR pilot project in a carbonate reservoir which will be a harbinger for North Kuwait’s efforts to exploit EOR reserves.
Temizel, Cenk (Area Energy) | Zhang, Ming (University of Kansas) | Biopharm, Frontida (University of Kansas) | Jia, Bao (University of Kansas) | Putra, Dike (Energy Rafflesia) | Moreno, Raul (Consultant) | Al-Otaibi, Basel (Kuwait Oil Co.) | Alkouh, Ahmad (Middle East Oilfield Services)
Per recent analyses, in the near future, over half amount of the oil extracted globally will require some form of enhanced oil recovery (EOR) technique. Existing literature and historical investigations suggest that in oil reservoirs having viscosities between 10 — 150 m. Pa.s, there is a substantial prospective for tertiary recovery through the implementation of polymer flooding. For reservoir oil viscosities above 150 mPa.s, the polymer pumping efficiency goes down as polymer injectivity reduces significantly with increasing injection water viscosity that is used to attain a favorable mobility ratio at such high oil viscosities. To overcome this limiting factor, in this study, we propose the use of supramolecular assemblies (SMA) that have adjustable viscosity properties. Complex long-chain amino-amides and maleic acid are used to make these assemblies, which allow it to have reversible viscosity depending on the solution pH level.
To maintain high injection efficiency, during pumping, SMA solutions will be kept at low viscosity values. On entry in deep reservoir or at oil contact phase, through introduction of an external stimulus, the viscosity of SMA solution will be reversed to a much higher viscosity. This will allow to sufficiently improve the mobility ratio. Preliminary results from lab-scale studies have indicated that along with reversibly adjustable viscosity property, SMA solutions are also tolerant to high temperatures and salt concentrations.
Supramolecular solutions can be contemplated as remedy polymer systems, since unlike conventional polymers they disassemble and re-assemble when exposed to high temperature and stress conditions. In such conditions, conventional polymers generally undergo degradation. Additionally, through molecular scission processes SMA solutions can also be used in highly confining environments as well as in permafrost conditions and thin zones where conventional thermal techniques are not applicable.
The objective of this work is the development of a novel SMA system that has the aforementioned properties of reversibly adjustable viscosity through pH, tolerance to high temperature and salt concentrations through desired interfacial properties. Lab-scale preliminary results have shown the potential economic benefits of the use of SMA solutions on a field-wide scale. Based on the results, it must be emphasized that SMA systems have a worldwide application in oil reservoirs for EOR purposes.
The saturation distribution after unstable waterflooding for highly viscous oil may have a decisive effect on the efficiency of tertiary polymer flooding, in particular because of hysteresis effects associated with oil banking. This paper addresses the challenges in modeling highly unstable waterflooding, using both a conventional Darcy-type simulator and an adaptive dynamic prenetwork model, by comparing the simulated results with experimental data including saturation maps. It also highlights the important role of relative permeability hysteresis in the tertiary recovery of viscous oils by polymer injection.
Yegin, Cengiz (Texas A&M University) | Zhang, Ming (Biopharm Frontida) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Balaji, Karthik (University of Southern California) | Peksaglam, Zumra (University of Southern California) | Dhannoon, Diyar (Texas A&M University) | Putra, Dike (Rafflesia Energy) | Wijaya, Zein (HESS) | Saracoglu, Onder (Consultant) | Temizel, Cenk (Aera Energy)
Current analyses indicate that 50% of oil produced in USA and the world will be through EOR technologies in the next 20-25 years, and heuristics suggest that polymer flooding should be applied in reservoirs with oil viscosities between 10 and 150 mPa.s. The key factor limiting the recommended range is that for oil viscosities greater than 150 mPa.s, where injected water viscosity values required for a favorable mobility ratio give rise to prohibitively low values of polymer injectivity and pumping efficiencies. Herein, we propose that a novel type of supramolecular system based on the complexation of long chain amino amides and maleic acid with reversibly adjustable viscosities can enable us to overcome the injectivity limitation.
The concept is that viscosity of the injected supramolecular system will be maintained initially at low values for easy injection and pumping, and then increased by means of an external pH stimulus just before or upon contacting oil. Our promising lab-scale preliminary studies have indicated that such supramolecular systems possess not only reversible pH-responsive properties, but are also very tolerant to high salinities and temperatures.
While polymers degrade and break up upon experiencing sudden extreme shear stresses and temperatures, supramolecular solutions merely disassemble and re-assemble. Therefore, supramolecular solutions can be considered as healable polymer solutions in a way. Supramolecular solutions can adapt to the confining environment. For instance, when a high molecular weight polymer macromolecule is forced to flow into narrow channels and pores, molecular scission processes may take place.
Supramolecular solutions can have a significant impact in the cases where thermal methods cannot be used for some viscous oils due to thin zones, permafrost conditions and environmental constraints. This project is primarily aimed at developing novel supramolecular assemblies with adjustable viscosity and interfacial properties that have robust tolerance against high temperatures and salinities. Such supramolecular assemblies will be used to significantly improve the feasibility and cost-effectiveness of displacement fluids used in EOR. Overall, there is a significant potential for application of supramolecular solutions in the US and throughout the world.
The effect of geochemical reactions and the kinetics of minerals are not completely understood in reactive-transport problems such as low-salinity waterflooding (LSF) or alkaline/surfactant/polymer (ASP) injection method. These processes do not only act as an inert displacement and geochemistry also plays a major role in the fluid behavior and oil recovery. In this paper, first, the importance of the kinetics of minerals with fast and slow rate kinetic reactions (e.g., calcite and quartz, respectively) in different conditions during reactive-transport floods is investigated using PHREEQC geochemical package. Then, two-phase Buckley-Leverett (BL) flow is coupled with IPhreeqc which is open-source module of the PHREEQC geochemical package in order to study the effect of the geochemical reactions and the kinetics of minerals on the oil recovery in two different displacement distances. This coupling provides a simple tool for modeling the geochemical reactions to understand the effect of the geochemistry on the two-phase and 1D flow, and consequently the oil recovery. Finally, as an example, the significance of the kinetics of minerals in LSF and in oil recovery is studied at two different scales.
The results show that temperature, in-situ water composition and buffering capacity have a great impact on the kinetics of mineral. It has been shown that minerals with slow rate kinetic reaction (e.g., quartz) might be excluded in reactive-transport phenomena at core-scales. However, minerals with fast rate kinetic reactions (e.g., calcite) must be included when modeling lab results. On the other hand, the residence time at field-scales is large enough for the mineral dissolution and precipitation to affect the local equilibrium constants. Therefore, in modeling field-scale applications, local equilibrium assumption (LEA) can be applied for fast rate kinetic minerals, whereas kinetics should be used for slow rate kinetic minerals (e.g., quartz).
Polymer flooding has now become a relatively well accepted method to increase production and recovery in heavy oil fields. Numerous pilots have taken place these last few years and field expansions are currently ongoing in several fields such as Pelican Lake (Canada), Marmul (Oman), Bohai Bay (China), Diadema (Argentina) and Patos Marinza (Albania).
As a result of these recent developments, field data has now become available in large quantity and can be used to provide guidance on the impact of various parameters on expected flood performances. For instance, a comparison of primary, secondary and tertiary polymer flood performances based on the analysis of several polymer flood patterns in Pelican Lake was presented in 2016 (
The present paper proposes to go further and to investigate the impact of parameters such as pore volume injected, well length, well spacing or Voidage Replacement Ratio (VRR) on polymer flood performances, based on data from fields in Canada and other parts of the world.
The performances of over 70 patterns belonging to several heavy oil polymer floods were analyzed and the impact of VRR, well spacing, well length and other parameters on recovery was evaluated. The calculations were performed using actual reservoir and production data whenever possible and published data in other cases.
Despite a large scatter in the data due to the wide range of reservoir conditions investigated, it is possible to distinguish interesting trends. For instance, higher VRR corresponds to lower recovery and recovery is fairly well correlated to injected pore volumes.
This paper will provide guidance to engineers designing polymer floods in heavy oil fields, allowing to adjust some of the design parameters to improve field response. In addition, the results can also be used to benchmark reservoir simulation results which can often be too optimistic or to compare performances of pilot projects in other fields.