The traditional definition of volumetric sweep efficiency sums the effects of both fingering (arising due to contrasts in mobility) and bypassing (arising due to contrasts in permeability as well as well placement). Accordingly, we cannot quantitatively attribute poor sweep to either bypassing or fingering. Similarly, in EOR, the incremental recovery cannot be quantitatively associated with the reduction of those effects. For such purposes, we rely on visualization and mapping of saturation profiles to quantify and characterize the remaining oil in place including its distribution. . In this work, we propose a complementary method to obtain an instantaneous insight of the remaining oil distribution. We demonstrate the decomposition of fingering and bypassing effects and its utility. We first redefine recovery factors such that we decouple bypassing and fingering effects. We then validate those redefined sweep indicators by examining a 5-spot waterflood and two idealistic polymer floods. Later, we demonstrate the possible utility of those redefined sweep indicators through different examples. In one example, we compare the performance of a shear - thinning polymer to a recovery-equivalent Newtonian polymer. Using fingering and bypassing sweep indicators, we can immediately conclude that the shear-thinning polymer exacerbates bypassing. We recommend the adoption of our redefined sweep indicators in any simulation suite. They provide instant understanding of sweep and hence can be complementary to standard practices of oil saturation mapping and of special value when analyzing the results of multiple realizations and/or development scenarios.
Bhushan, Yatindra (ADNOC Onshore) | Ali Al Seiari, Reem (ADNOC Onshore) | Igogo, Arit (ADNOC Onshore) | Hashrat Khan, Sara (ADNOC Onshore) | Al Mazrouei, Suhaila (ADNOC Onshore) | Al Raeesi, Muna (ADNOC Onshore) | Al Tenaiji, Aamna (ADNOC Onshore)
A reservoir simulation study has been performed to assess the enhanced oil recovery benefits for a proposed pilot on Simultaneous Injection of Miscible Gas (CO2) and Polymer (SIMGAP) in a giant carbonate reservoir (B) in Abu Dhabi. The model has been used to carry out uncertainty analysis for various input parameters and analyze their impact on pilot performance. The paper discusses the uncertainty analysis in detail.
Reservoir-B consists of B_Upper and B_Lower layers which are in full hydrodynamic equilibrium. However, in the southern and western parts of the reservoir, the B_Upper layer has permeabilities that are one to two orders of magnitude higher than the B_Lower layer. The reservoir is on plateau production under waterflooding, however, it is observed that there is water override in B_Upper. The B_Upper layer is being waterflooded very efficiently, while the B_Lower layer remains largely unflooded and forms the key target for enhanced oil recovery (EOR).
The proposed SIMGAP pilot plans to inject polymer into the B_Upper layer and CO2 into the B_Lower layer with producers in the B_Lower layer. The pilot will utilize a line drive pattern at 250m spacing using 3000 ft horizontal wells. There will be two central horizontal injectors (one in B_Upper and the other in B_Lower) and two horizontal producers (one on either side of the central injectors).
Pilot uncertainty analysis cases have been run by varying different parameters that could impact the pilot performance. The parameters that have been varied are polymer viscosity, polymer adsorption, residual resistance factor, thermal stability of polymer, residual oil to miscible flooding (Sorm), residual oil to water flooding (Sorw), Krw end point, high perm streaks, fracture possibility and extension to B_Upper or B_Lower layers, three phase oil relative permeability models, maximum trapped gas saturation, dense zone permeability and pore volume uncertainty. In addition, a grid sensitivity study was undertaken to test the sensitivity of the process to varying levels of dispersion. The results suggest that the key uncertainties which have impact on recovery are polymer viscosity, polymer adsorption, residual oil saturation to water and CO2, presence of high perm streaks and maximum trapped gas saturation values. Vertical observation wells located between the injector and producer wells (equivalent to 0.3 to 0.4 PV of CO2 injection in B_Lower), will be used to confirm whether the SIMGAP process has been successful in containing CO2 in the B_Lower layer and thereby suppressing crossflow.
Moreno Ortiz, Jaime Eduardo (Schlumberger) | Klemin, Denis (Schlumberger) | Savelyev, Oleg (Gazprom Neft Middle East B.V.) | Gossuin, Jean (Schlumberger) | Melnikov, Sergey (Gazpromneft STC) | Serebryanskaya, Assel (Gazprom Neft Middle East B.V.) | Liu, Yunlong (Schlumberger) | Gurpinar, Omer (Schlumberger) | Salazar, Melvin (Schlumberger) | Gheneim Herrera, Thaer (Schlumberger)
Use of numerical models to characterize and evaluate reservoir potential is an industry wide practice, with increasingly more development decisions being substantiated by finite difference models. Advances on hardware and software, along with the ability to effectively incorporate accurate process physics, makes simulation a robust tool for field development decisions, particularly on complex operations such as enhanced oil recovery and/or reservoirs with challenging heterogeneity and pore structures. Use of these models does not come without its challenges where data requirements (and use of special characterization both at lab and field level) increase as does the reservoir characterization granularity and thus model sizes. Unsurprisingly the increase of model precision and data requirements amplifies non-uniqueness of the numerical solutions obtained during any field evaluation including field development planning (FDP). Incomplete/inconsistent datasets pose a further challenge to the accuracy (and arguably risk) of the forecasts by introducing further uncertainty on the process characterization. Use of complementary technology such as digital rock, that would enable mitigate impact of such uncertainties in a timely manner -either at field or laboratory level, is thus highly desirable particularly when dealing with enhanced oil recovery. Compounding the non-linearity effect of the EOR agent characterization is the effect of the augmented numerical artifacts (dispersion, dilution, etc) of which complex chemical implementations are prone to, making the upscaling process from laboratory dimensions to field more complex.
As part of enhanced oil recovery (EOR) strategic objectives to boost oil recovery towards 70% aspiration and demonstrate EOR as an attractive viable option for environmental Carbon Capture, Utilization and Storage (CCUS) applications, various conventional and novel EOR technologies and applications are being screened and studied to ensure meeting mandated objectives. Accordingly, number of EOR pilots and projects have grown substantially over recent years to ensure derisking the full field expansion uncertainties and challenges, especially in such carbonate reservoirs with harsh conditions of temperature ( 250 F) and salinity ( 200,000 ppm). Detailed screening study and performance review assessment have been conducted, in which gas and chemical based EOR technologies were identified for targeted reservoirs. The candidate reservoirs have a long history of EOR projects focusing on miscible hydrocarbon gas (HC) as early as 1996, which has supported oil production meeting forecast demand. On the other hand, as part of environmental driven strategy for CCUS and EOR applications, CO2 technology has been successfully progressing as EOR business case full-integrated cycle from pilot to field expansion during 2009-2016. In 2016, Al Reyadah has been launched as a unique commercial-scale CCUS facility in the region, that captures 800,000 tonnes of CO2 annually from Emirate Steel Industries and injects it into oilfields to boost crude recovery. Furthermore, novel EOR technologies have been screened and identified with significant potential added value, that includes SIMGAP, SIWAP, Surfactant, Polymer and others, which are currently under modeling and design phase for implementation within upcoming few years to boost recovery factor towards 70% aspiration. Development and piloting of latest technologies are among the main enablers to ensure fit-for purpose applications, proper planning and optimum design for ultimately maximum revenue economically. This paper presents a big-picture overview of EOR technologies with the focus on some cases, challenges and opportunities for super giant carbonate reservoirs. 2 SPE-196693-MS
Jackson, A. C. (Chevron Corporation) | Dean, R. M. (Chevron Corporation) | Lyon, J. (Chevron Corporation) | Dwarakanath, V. (Chevron Corporation) | Alexis, D. (Chevron Corporation) | Poulsen, A. (Chevron Corporation) | Espinosa, D. (Chevron Corporation)
Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results.
Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments.
The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity.
Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells.
The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.
Yudhowijoyo, Azis (University of Aberdeen) | Rafati, Roozbeh (University of Aberdeen) | Sharifi Haddad, Amin (University of Aberdeen) | Pokrajac, Dubravka (University of Aberdeen) | Manzari, Mehrdad (University of Aberdeen)
Crosslinked polymer gels have been widely used to overcome water and gas coning problem in the petroleum industry. Recently, nanoparticles are identified to have a potential of reinforcing the polymer gel systems by improving physical bonding and heat transfer properties in the gel structure. In this study, silicon dioxide and aluminium oxide nanoparticles were introduced to xanthan gum polymers that were crosslinked by chromium (III) acetate, to create polymeric nanocomposite gels with higher shear strengths. The gelation time and gel strength have been selected as main parameters to evaluate the effect of nanoparticle types and concentrations on the nanocomposite gels performance. The gelation time is measured until the onset of gelation or the moment when apparent viscosity starts to increase at 60°C. The gel strength is represented by the storage modulus (G’) after 24 hours of gelation at 60°C. Both parameters were measured by a rheometer, through constant shear rate and oscillatory tests respectively.
The addition of 1000 and 10000 ppm of silicon dioxide (SiO2) nanoparticles into a solution of 6000 ppm xanthan gum polymers that are crosslinked with 50000 ppm chromium (III) acetate caused insignificant changes in gelation time. Similar result was also reported when 1000 and 10000 ppm of aluminium oxide (Al2O3) nanoparticles was introduced into the polymer system. This suggests that when SiO2 and Al2O3 nanoparticles are introduced to xanthan/chromium (III) Acetate system for field application, no additives would be required to prolong or shorten gelation time to counter the nanoparticles addition. To analyse the gel strengths, the results from the oscillatory test were averaged throughout the frequency range, and it was shown that the addition of SiO2 nanoparticles decreases the average storage modulus from 75.1 Pa without nanoparticles, to 72.3 Pa at the nanoparticles concentration of 1000 ppm. However, the average storage modulus increased to 83.0 Pa and 94.7 Pa at higher nanoparticles SiO2 concentrations of 5000 ppm and 10000 ppm. The same trend was observed for the nanocomposite gels that were produced by Al2O3 nanoparticles. Similarly, the storage modulus decreased initially to 70.8 Pa at the concentration of 1000 ppm, then it increased to 89.9 Pa and 109.4 Pa at nanoparticles concentrations of 5000 pm and 10000 ppm, respectively. Hence, the nanoparticle-enhanced biopolymer gels showed insignificant changes of gelation time, and at the same time, they demonstrated up to 45% improvements in the gel strength properties when the nanoparticles concentration is higher than 5000 ppm.
In conclusion, the nanocomposite gels demonstrated reinforced bonding properties and showed higher gel strengths that can make them good candidates for leakage prevention from gas wells and blocking of water encroachments from aquifers into the wells.
This paper summarizes a technology using SMP to provide downhole sand control in openhole environments. With multistage operations becoming the industry norm, operators need easily deployable diversion technologies that will protect previously stimulated perforations and enable addition of new ones. This paper reviews several aspects of the use of in-stage diversion. Development of a new polymer composite that degrades via hydrolysis in hot water or brine holds potential for use in structural applications for intervention-less downhole tools. The polymer-injection project in the Dalia field, one of the main fields of Block 17 in deepwater Angola, represents a world first for both surface and subsurface aspects.
Polymer flooding in sensitive areas can require the transport of polymer fluids over long distances. Conventional wisdom limits transport distance or degradation occurs. This paper argues that critical velocity, not distance, is the controlling factor. Polymer flooding has been used to enhance the production of oil from mature fields in Oman. This article discusses the trial of several approaches to improve the treatment of water produced from these fields.
Researchers from Chevron are looking into a new approach to understand the drivers of polymer hydration. How might this affect the design of mixing systems in the field, and could it affect offshore EOR applications? Fluid Efficiency and Rhapsody Venture will partner to refine and launch a new molecular technology to improve the flow in pipelines. In this second article of a series covering water management in hydraulic fracturing (HF) in unconventional resources, the properties and characteristics of the flowback fluids are discussed, together with the general categories of technologies that are best suited to treat them. This is the first of several articles on the subject of water management for unconventional hydraulic fracturing.
Aker Solutions and FSubsea have agreed to a joint venture, named FASTSubsea, to help operators increase oil recovery. High-concentration polymer flooding can improve oil-displacement efficiency but separation of oil/water mixture becomes more difficult because of emulsification. In this work, a case history of dehydration technology for HCPF production and lab investigation of emulsion behaviors are reviewed. The authors discuss the results of a pilot project to capture post-combustion CO2 for purposes of EOR. Produced water from chemical floods can cause problems for separation and water treatment equipment due to the polymers and surfactants used.