Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Wang, Zhe (Research Institute of Petroleum Exploration and Development, CNPC) | Wu, Kangyun (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration and Development, CNPC) | Long, Hang (Research Institute of Petroleum Exploration and Development, CNPC)
Lab study of chemical EOR for the carbonate reservoir was performed through core characterization, chemical formula screening, surfactant adsorption losses experiments and oil displacement core flooding tests of chemical flooding.
The research results lay the foundation of future pilot tests for chemical combination flooding applying to carbonate reservoirs.
Core characterization by scanning electron microscope and mercury injection capillary pressure experiment prove that there are plenty micropores and a few emposieu within rock, porosity of formation cores is relatively high but permeability is low, the reservoir lithology belonged to typical biostromal carbonate reservoir and the heterogeneity is severe. Chemical flooding formula was investigated by polymer and surfactant screening tests. Salt tolerant polymers including STARPAM and KYPAM showed good viscosifying performances than conventional polymer when prepared with formation water. Amphoteric surfactant AS-13 and anion-nonionic surfactant SPS1708 were selected and ultra-low interfacial tension between crude oil and formation water can be obtained in alkali-surfactant-polymer (ASP) and alkali free surfactant-polymer (SP) systems. Adsorption losses of surfactants on core sample showed that the dynamic adsorption losses of surfactant AS-13 and SPS1708 were 0.46mg/g and 0.37mg/g respectively. Core flooding tests of chemical flooding proved that more than 17~18% incremental oil recovery over water flooding could be obtained with ASP (0.6wt% Na3PO4 + 0.3wt% surfactant + 1000ppm polymer) or SP (0.3wt% surfactant + 1000ppm polymer) flooding. The effect of both ASP and SP flooding was better than that of surfactant flooding.
The experimental results are considered to be technical feasibility and confirm the effectiveness of chemical EOR methods especially the SP flooding for the biostromal carbonate reservoir, which may present further understanding for chemical EOR field application in carbonate reservoirs.
Polymer flooding is a well established tertiary EOR technique to improve mobility control of a waterflood. Currently partially hydrolyzed polyacrylamide (HPAM) is the industry workhorse in polymer EOR in reservoirs with low salinity and temperature. Biopolymers including hydroxyethylcellulose (HEC) and Xanthan are soluble and excellent viscosifiers in high salinity conditions. This paper will provide a literature review on the use of biopolymers for EOR and focus specifically on the benefits of HEC as a mobility control polymer.
Polymer flooding is investigated in laboratory corefloods for potential application in a 2000 cP - 5000 cP heavy oil field. An incremental oil recovery is noted with the addition of very low concentrations of partially-hydrolyzed polyacrylamide (HPAM), either in secondary or tertiary (i.e. after waterflooding) injection. However, increasing polymer viscosity from 3 cP to 60 cP does not significantly change recovery from two pore volumes (PV) of tertiary polymer injection.
Existing scaling groups for viscous instability are investigated. Corefloods in this study and others are found to be in or near the transition zone, where recovery may be sensitive to variables such as core diameter, while field floods are all in the "pseudo-stable?? region, where this may not be the case.
Mounting evidence suggests that polymer flooding can be economically applied to very viscous oils, despite the fact that it is not feasible to obtain unit mobility ratio with non-thermal methods. Additional work is necessary to determine appropriate optimization methods and criteria for these floods.
In May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 103m3 (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 103m3 (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible.
A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations.
Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells.
The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.
Koroteev, Dmitry Anatolyevich (Schlumberger) | Dinariev, Oleg (Schlumberger) | Evseev, Nikolay (Schlumberger) | Klemin, Denis Vladimirovich (Schlumberger R&D Inc.) | Safonov, Sergey (Schlumberger) | Gurpinar, Omer M. (Schlumberger) | Berg, Steffen (Shell Global Solutions International BV) | vanKruijsdijk, Cor (Shell) | Myers, Michael (Shell) | Hathon, Lori Andrea (Shell International E&P Co.) | de Jong, Hilko (Shell Oil Co.) | Armstrong, Ryan (Shell)
Fast and reliable EOR process selection is a critical step in any EOR project. The digital rock (DR) approach jointly developed by Shell and SLB is aimed to be the smallest scale yet advanced EOR Pilot technology. In this document, we describe the application of DR technology for screening of different EOR mechanisms at pore-scale focused to enhance recovery from a particular reservoir formation. For EOR applications DR brings unique capabilities as it can fully describe different multiphase flow properties at different regimes.
The vital part of the proposed approach is the high-efficient pore-scale simulation technology called Direct Hydrodynamics (DHD) Simulator. DHD is based on a density functional approach applied for hydrodynamics of complex systems. Currently, DHD is benchmarked against multiple analytical solutions and experimental tests and optimized for high performance (HPC) computing. It can handle many physical phenomena: multiphase compositional flows with phase transitions, different types of fluid-rock and fluid-fluid interactions with different types of fluid rheology. As an input data DHD uses 3D pore texture and composition of rocks with distributed micro-scale wetting properties and pore fluid model (PVT, rheology, diffusion coefficients, and adsorption model). In a particular case, the pore geometry comes from 3D X-ray microtomographic images of a rock sample. The fluid model is created from lab data on fluid characterization. The output contains the distribution of components, velocity and pressure fields at different stages of displacement process. Several case studies are demonstrated in this work and include comparative analysis of effectiveness of applications of different chemical EOR agents performed on digitized core samples.
Haynes, Andrew Kenneth (Chevron Australia Pty Ltd) | Clough, Martyn David (Chevron Australia Pty Ltd) | Fletcher, Alistair J. P. (Chevron Australia Pty Ltd) | Weston, Stuart (Chevron Australia Pty Ltd)
Barrow Island's Windalia reservoir is Australia's largest onshore waterflooding operation and has been under active waterflood since 1967. The highly heterogeneous reservoir consists of fine-grained, bioturbated argillaceous sandstone that is high in glauconite clay. The high clay content results in a low average permeability (5 md) despite high porosities (25-30%) and hence fracture stimulation is required to achieve economic production rates.
The Windalia reservoir and fluid properties preclude the use of traditional EOR technology, with thermal, miscible and mobility control processes all deemed unfeasible through screening studies. Consequently, the in-depth flow diversion mechanism was developed and applied, which utilizes a low molecular weight polymer to drive the growth of induced hydraulic fractures in the treated injection wells. A 3-injector pilot was executed involving polymer injection for two years, with no detrimental injectivity losses observed for polymer concentrations up to 750 ppm. Considerable fracture growth, oil production rate uplift and reduction in water cut were observed throughout the pilot pattern, in line with predictions:
• Fracture half-lengths increased from 6 ft to 400 ft in one injector and from 141 ft to 322 ft in another
• An initial oil rate uplift of 38% relative to the production baseline was observed; a more conservative estimate suggested that at least half of this was attributable to the tertiary recovery process
• The water-oil ratio was observed to fall from 15 to 11, similarly timed with the oil production increase.
These improvements were observed consistently throughout the pilot area and were distinct from the waterflood behavior elsewhere in the field. This paper briefly summarizes the technology screening and pilot execution stages, after which the results from the pilot are presented and discussed. This technology may be of use in other low-permeability waterfloods with induced injector fractures, for which traditional EOR practices are believed to be unfeasible.
The development of chemical enhanced oil recovery projects throughout the world is on a fast pace, led by a will to increase the final recovery of mature and newly developed hydrocarbon reservoirs The validation of the process is usually achieved by implementing an injection pilot; the goal is to understand, secure, and optimize the technology and to assess its efficiency on increasing final oil recovery for carefully determined capital and operational expenditures.
One of the key factors for a successful polymer flood is the polymer solution viscosity that must remain on target during the transport from its initial preparation, to the well head and down to the reservoir. Thus, a reliable method is required to measure and monitor the polymer solution viscosity on different points along the dissolution, dilution, mixing, and injection lines. This method must take into account the polymer solution characteristics among which the non-Newtonian behavior and sensitivity to mechanical and chemical degradations.
This paper presents recent developments of a specific in-line viscometer, which can measure the viscosity at low shear-rate, as per real reservoir conditions, with pressures ranging up to 250 barg. The equipment consists in a low flow, non-shearing pump, which circulates the solution through a given tube (length and diameter) where the pressure drop is measured and allows low-shear viscosity to be extrapolated. Calibration methods and first results are presented in this paper to illustrate the accuracy of the technology and potential installation benefits for chemical enhanced oil recovery operations. The viscometer is made of highly resistant material and can be implemented in all hazardous areas in remote mode without manual operations, no waste and very little maintenance.
This new device has been designed to solve the common issues encountered with the vast majority of commercial equipment that is not compatible with currently injected polyacrylamide solutions. It will also allow operators to gather reliable data compared to manual sampling methods that, in addition to requiring manpower, are not easy to conduct without degrading the polymer solutions.
Angsi field is slated to be the first in the world for Alkaline-Surfactant and Polymer (ASP) chemical flooding via a floating structure in an offshore environment. The chemical flooding will be for 3 years with 6 months of low salinity water pre-flush injection prior to chemical injection to condition the reservoir, and 6 months of treated seawater with polymer injection as post-flush activity. The chemical flooding will be conducted via injection of treated and partially desalinated seawater mixed with ASP chemicals produced from the floater which is tie-in to the existing Angsi water injection pipeline network (Figure 1.0). Angsi reservoirs will experience three (3) different salinity range exposures with two (2) as invading fluids with effects of chemical cocktail, wettability and fluid distribution. One of the main challenges for ASP flooding in an offshore environment is handling the chemical residuals breakthrough in produced water causing the water unable to be disposed overboard. To overcome this problem and to eliminate environmental pollution, a full scale Produced Water Re-Injection (PWRI) system with full integration to existing Angsi Produced Water Treatment (PWT) system should be adopted to meet the new water reinjection specifications. Since the PWRI water will be commingled with treated and partially desalinated seawater mixed with ASP chemicals from the floater, it is paramount to predict the range of salinity of the produced water over time to help to design the PWRI and Floater's water treatment system to achieve the final water quality and optimum salinity required for an effective ASP cocktail for re-injection. This paper will summarise the PWRI design and operation philosophy coupled with subsurface studies to predict salinity profiles for the produced water.
This paper discusses a structured combination of procedures used to investigate polymers for EOR application with the focus on performance, compatibility with production chemicals and phase behaviour. This approach allows for early identification of risks and points to further work necessary for mitigation before field implementation. The case studied here was a system with total dissolved solids (TDS) of 80000 mg/l and temperature requirements of 40 to 70 oC. Effective screening of polymers has benefited from dissolution/viscosity, thermal stability and filtration tests. At lower temperatures (40 oC), polymers were shown to be fit-for-purpose for the conditions evaluated. All polymers showed loss of viscosity with some leading to complete viscosity loss at increased temperatures. This is the result of hydrolysis and interaction with the divalent cations present in the make-up synthetic brine. In-situ viscosity allowed for identification of phase behaviour effects which could affect injectivity (difference in apparent and rheometer viscosity). For the best performing polymer the presence of corrosion and scale inhibitors did not affect viscosity. No detrimental effects on corrosion inhibition and water in oil emulsions were observed. Increases in oil in water with potential fouling/deposition was identified for future study.
EOR technology has been applied on many projects globally with variable success. It shows great potential for offshore heavy oil with oil recovery low in life span of platform (general less than 30% by water flooding). About 60-70% oil is remained in the formation after water flooding, and for offshore heavy oil reservoir, more oil (about 80%) is remained by the end of the platform life.  It becomes more important to achive high recovery before abandoning the platform and the oilfields with lots of oil left in reservoir. With recovery increasment of 5-10% by EOR methods, the reserve will increase greatly, which means an order of magnitude of hundreds of million-tons oilfield is discovered without increase any exploration investment.
Surfactant-polymer (SP) flooding was a potential enhanced oil recovery (EOR) technology that was more powerful than the polymer flooding. And it was test or applied successfully in some high or extra-high WCT onshore oilfields of Shengli oilfields (SINOPEC), Daqing oilfields (CNPC) in china. The paper presents a filed EOR test case of offshore heavy oilfield oilfield by SP.