Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.
This page provides a brief review of illustrative field applications of polymer waterflooding as reported in the literature. In 1983, Manning et al. published a comprehensive and classic summary of the field results and performance of more than 250 polymer waterflooding projects and provided information relating to the early field applications of polymer waterflooding. Figure 1 shows the incremental oil production response for the North Burbank polymer flood. A polymer waterflooding project that involved a large full-field flooding project at the North Oregon Basin field in Wyoming's mature Big Horn Basin oil-producing area was reported in 1986 to be producing 2,550 BOPD of incremental oil production. It was reported that this polymer flooding project would recover ultimately more than 10 million bbl of incremental reserves from the mature North Oregon Basin field. The field project involved the flooding of both a fractured carbonate formation and a fractured sandstone formation with a polymer flood using partially hydrolyzed polyacrylamide(HPAM).
In this study, conceptual numerical simulation models, with geomechanical properties incorporated, were employed to assess whether polymer flooding or a surfactant EOR process could be viable; with minimal damage to permafrost. These simulations considered the geological subdivisions of permafrost distribution in the subsurface which included: an active layer (seasonally frozen ground); taliks (unfrozen ground between the base of the active layer and permafrost layer and within the permafrost layer); and the unfrozen layer below the permafrost zone. In addition, a major oil zone was included in the model underlying the permafrost section. Significant oil recovery values were predicted, both for injection of polymer solutions and surfactant-polymer solutions and with both horizontal and vertical wells. Surprisingly, addition of surfactant provides lower oil recovery than for polymer flooding alone (under same injection slug size, when all subdivisions were considered in the model). This result appeared to occur because the thermodynamics build into models allows the surfactant formulation to freeze easier than the polymer solution without surfactant. This freezing depletes the surfactant bank, and therefore, lowers oil recovery. On the other hand, this freezing actually promotes growth of the permafrost, whereas, injection of polymer alone causes a mild thawing of the permafrost. One might question whether the thermodynamics built into the simulator are correct, but this result does emphasis that in addition to temperature, the chemistry of the injected formulation may be important in determining the fate of the permafrost. At a certain well distance to permafrost (1,640 ft), horizontal injection wells cause greater thawing of permafrost than vertical wells, when wellbores are close to the taliks. Higher concentration and viscosity of polymer slugs have small potential for thawing permafrost, largely because of the injectivity reduction during polymer flooding (thus allowing slower heat dissipation). Examination of polymer injection as a function of pressure, temperature, and mean stress, suggests that subsidence of permafrost could be negligible. The effects on permafrost subsidence increases modestly as the polymer slug size increases, and decreases modestly as the surfactant-polymer slug size increases. As huge heavy oil reserves exist in Canada and Alaska's North Slope regions, continued resource development in these regions is likely. Therefore, a thorough understanding is required in considering the long-term impact on permafrost stability with the use of modern EOR processes implemented in this unique environment.
Ning, Samson (Hilcorp) | Barnes, John (Hilcorp) | Edwards, Reid (Hilcorp) | Dunford, Kyler (Hilcorp) | Eastham, Kevin (Hilcorp) | Dandekar, Abhijit (University of Alaska, Fairbanks) | Zhang, Yin (University of Alaska, Fairbanks) | Cercone, Dave (National Energy Technology Laboratory) | Ciferno, Jared (National Energy Technology Laboratory)
Alaska North Slope (ANS) holds an estimated 20-30+ billion barrel heavy oil resources, yet the development pace has been very slow due to high development costs and low oil recovery using conventional waterflood and EOR methods. The objective of this pilot is to perform a field experiment to validate the use of an advanced polymer flooding technology to unlock the vast heavy oil resources on ANS.
The advanced polymer flooding technology combines polymer flooding, low salinity water flooding, horizontal wells, and if necessary, injection conformance control treatments into one integrated process to significantly improve oil recovery from heavy oil reservoirs. Two pairs of horizontal injection and production wells have been deployed in an isolated fault block of the Schrader Bluff heavy oil reservoir at the Milne Point Field to conduct a polymer flood pilot. The pilot will acquire scientific knowledge and field performance data to optimize polymer flood design in the Schrader Bluff heavy oil reservoirs on ANS.
Polymer injection started on August 28, 2018 using a custom made polymer blending and pumping unit. This paper focuses on the facility setup and polymer injection performance into the horizontal injectors drilled and completed in the Schrader Bluff heavy oil reservoir. Partially hydrolyzed polyacrylamide (HPAM) polymer was selected and the initial target viscosity was set at 45 centipoise. Polymer injection rate was set at 2200 bbl/day for one injector (J-23A) and 1200 bbl/day for the other (J-24A) based on production voidage. Injection pressure was controlled below or slightly higher than fracture pressure to prevent fracture extension in the reservoir causing fast breakthroughs. Step rate and pressure falloff tests indicate that short term polymer injectivity is similar to water injectivity, which means that injectivity is mostly controlled by fluid mobility deep in the reservoir rather than that in the vicinity of the injection wellbore. Long term injection data indicate that polymer injectivity has been decreasing in both injectors as the reservoir is filled by polymer. No polymer has been observed in the production stream 9 months after the start of polymer injection compared with a 3-month breakthrough time with waterflood. This indicates that polymer significantly delays breakthrough time which will lead to increased sweep efficiency.
Application of horizontal wells and multi-stage fracturing has enabled oil recovery from extremely low permeability shale oil reservoirs, but the expected ultimate recovery (EUR) due to depressurization is only 5-10% of the original oil in place (OOIP). The objective of this work is to test whether coupling a chemical treatment with CO2 huff-n-puff can improve the oil recovery. The chemical blend (CB) contained an anionic surfactant and a persulfate compound in brine. Oil recovery efficiency of the CO2 with the chemical blend was compared with CO2 Huff-n-Puff cycles at different pressures (5200 psi, 4000 psi and 2800 psi). Outcrop Eagle Ford and Mancos core plugs were used in the study. This work shows that CO2 huff-n-puff is an efficient technique to improve oil recovery from oil shales. Most of the added oil was recovered in all the experiments. The pressure to which the cores were pressurized with CO2 did not affect the oil recovery significantly as long as it was high enough (2800 psi in these experiments). The addition of chemical blend seemed to impede the oil recovery. Because of the heterogeneity in shale samples, more experiments need to be conducted to understand and validate these conclusions.
Shale oil contributes more than 60% of the US oil production according to EIA (2019). Shale oil production has been feasible because of technological development for horizontal wells with multi-stage hydraulic fracturing. The hydraulic fracturing technique has improved significantly in recent years, but the estimated oil production in these unconventional reservoirs is less than 10%. For an average well, the oil production rates fall sharply in the first year (more than 75%) because of the extremely low permeability, microfracture closure, and large flow resistance at the matrix-fracture interface. To keep the sustainability of oil production from shale oil, it is essential to develop enhance oil recovery (EOR) techniques for unconventional reservoirs. There have been several investigations on surfactant-based treatments, water injection and CO2 huff-n-puff for shale EOR.
This work presents a laboratory investigation of miscible ethane foam for gas EOR conformance in low permeability, heterogeneous, harsh environments (<15md, 136,000ppm total dissolved solids with divalent ions, 165°F). The use of ethane as an alternative to CO2 presents several operational and availability strengths which may expand gas EOR applications to depleted or shallower wells. Coupling gas conformance also helps improve displacement efficiencies and maximize overall recovery. Minimum miscibility pressure displacement tests were performed for dead crude oil from the Wolfcamp Spraberry trend area using ethane and carbon dioxide. Aqueous stability, salinity scan, and static foam tests were performed to identify a formulation. Subsequent foam quality and coreflood displacement tests in heterogeneous carbonate outcrop cores were conducted to compare the recovery efficiencies of three processes: a) gravity–unstable, miscible ethane foam; b) gravity–stable, miscible ethane, and; c) gravity– unstable, miscible ethane processes. Slimtube tests comparing ethane to CO2 resulted in a lower MMP value for ethane. We identified a stable surfactant blend capable of Type I microemulsion and persistent foams in the presence of oil. Core floods conducted with gravity-unstable miscible ethane foam, gravity stable miscible ethane, and gravity-unstable miscible ethane recovered 98.4%, 61.9%, and 42.6% OOIP respectively. Our work shows that miscible ethane injection processes result in significant recoveries even under gravity-unstable conditions. The addition of foam further enhances overall recovery at laboratory scale, showing promise for field applications. Unconventional plays present a challenging set of operational conditions which include high temperature, high salinity, low permeability, and fracture networks. Aggressive development of plays and low primary recovery values reveal a potential for enhanced oil recovery methods. Our work demonstrates that miscible ethane foam has the advantage of better conformance control availability that can satisfy these requirements.
Enhanced oil recovery methods have been instrumental in recovering additional oil from reservoirs after primary recovery cycles. Gas injection EOR, in particular, has contributed to the profitable recovery of oil from deep fields with low permeabilities and light to medium oils (Taber et al., 1997). Gas injection processes employ the use of nitrogen, hydrocarbon, or carbon dioxide gases to increase incremental oil recovery; they can be classified as miscible where the important mechanisms of oil displacement are miscibility and interfacial tension (IFT) reduction or immiscible where viscosity reduction and oil swelling play notable roles (Lake et al., 2014). A recent worldwide biennial survey of EOR projects shows carbon dioxide (CO2) and steam EOR as dominant production processes (Moritis, 2010). Miscible CO2 processes in the United States recently eclipsed steam EOR processes at 308,564 b/d compared to steam EOR's 300,762 b/d (Oil & Gas Journal, 2012). Apart from general gas injection issues such as viscous fingering and stability, CO2 flooding has several specific operational drawbacks. Poor selection of metals in production tubing for wells producing from CO2 flooded fields can result in corrosion, delays, and increased capital expenditures due to the presence of carbonic acid in upstream and midstream operations (Kermani and Morshed, 2003). Additionally, the formation of carbonic acid near injectors can cause dissolution and subsequent precipitation of rock minerals and asphaltene precipitation (Marques and Pimentel, 2016). Commercially profitable CO2 EOR projects also require sufficient transport infrastructure as well as vast quantities of naturally available injectant gas (Martin and Taber, 1992).
Included are applications of foam for mobility control and for blocking gas. In 1989, Hirasaki reviewed early steam-foam-drive projects. In 1996, Patzek reviewed the performance of seven steam-foam pilots conducted in California. Early and delayed production responses were discussed for these pilots. Gauglitz et al. review a steam-foam trial conducted at the Midway-Sunset field of California.
Application of polymer flooding as a chemical Enhanced Oil Recovery (EOR) has increased over recent years. The main type of polymer used is partially hydrolyzed polyacrylamide (HPAM). This polymer still has some challenges especially with shear stability and injectivity that restrict its utility, particularly for low permeability reservoirs. Injectivity limits the possible gain by acceleration in oil production due to polymer flooding. Hence, good polymer injectivity is a requirement for the success of the operation. This paper aims to investigate the influence of formation permeability on polymer flow in porous media.
In this study, a combination of core flooding with rheological studies is presented to evaluate the influence of permeability on polymer in-situ rheology behavior. The in-situ flow of HPAM polymers has also been studied for different molecular weights. The effect of polymer preconditioning prior to injection was studied through exposing polymer solutions to different extent of mechanical degradation.
Results from this study reveal that the expected shear thinning behavior of HPAM that is observed in rheometer measurements is not observed in in-situ rheology in porous media. Instead, HPAM in porous media exhibits near-Newtonian behavior at low flow rates representative of velocities deep in the reservoir, while exhibiting shear thickening behavior at high flow rates representative of velocities near wellbore region. The pressure build-up associated with shear thickening behavior during polymer injection is significantly higher than pressure differential during water injection. The extent of shear thickening is high during the injection of high Mw polymer regardless of cores' permeability. In low permeable Berea cores, shear thickening and mechanical degradation occur at lower velocities although the degree of shear thickening is lower in Berea to that observed in high permeable Bentheimer cores. This is ascribed to high polymer retention in Berea cores that results in high residual resistance factor (RRF). Results show that preshearing polymer before injection into porous media optimizes its injectability and transportability through porous media. The effect of preshearing becomes favorable for the injection of high Mw polymers into low permeability formation.
This study discusses polymer in-situ rheology and injectivity, which is a key issue in the design of polymer flood projects. The results provide beneficial information on optimizing polymer injectivity, in particular, for low permeability porous media.
Schumi, Bettina (OMV E&P) | Clemens, Torsten (OMV E&P) | Wegner, Jonas (HOT Microfluidics) | Ganzer, Leonhard (Clausthal University of Technology) | Kaiser, Anton (Clariant) | Hincapie, Rafael E. (OMV E&P) | Leitenmüller, Verena (Montan University Leoben)
Chemical Enhanced Oil Recovery leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high Total Acid Number (TAN) could be produced by injection of alkali. Alkali might lead to generation of soaps and emulsify the oil. However, the generated emulsions are not always stable.
Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. Based on the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in formation of initial emulsions is observed.
Micro-model experiments are performed to investigate the effects on pore scale. For injection of alkali into high TAN number oils, mobilization of residual oil after waterflooding is seen. The oil mobilization is due to breaking-up of oil ganglia or movement of elongated ganglia through the porous medium. As the oil is depleting in surface active components, residual oil saturation is left behind either as isolated ganglia or in down-gradient of grains.
Simultaneous injection of alkali and polymers leads to higher incremental oil production in the micro-models owing to larger pressure drops over the oil ganglia and more effective mobilization accordingly.
Core flood tests confirm the micro-model experiments and additional data are derived from these tests. Alkali co-solvent polymer injection leads to the highest incremental oil recovery of the chemical agents which is difficult to differentiate in micro-model experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micro-models, the incremental oil recovery is also higher for alkali polymer injection than with alkali injection only.
To evaluate the incremental operating costs of the chemical agents, Equivalent Utility Factors (EqUF) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and hence lowest chemical incremental OPEX are incurred by injection of Na2CO3, however, the highest incremental recovery factor is seen with alkali co-solvent polymer injection. It should be noted that the incremental oil recovery owing to macroscopic sweep efficiency improvement by polymer needs to be taken into account to assess the efficiency of the chemical agents.
Shah, Swej (Delft University of technology) | As Syukri, Herru (Delft University of technology) | Wolf, Karl-Heinz (Delft University of technology) | Pilus, Rashidah (Universiti Teknologi PETRONAS) | Rossen, William (Delft University of technology)
Foam reduces gas mobility and can help improve sweep efficiency in an enhanced oil recovery process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that local pressure gradient exceeds a critical value (∇Pmin). Normally, this only happens in the near-well region. Away from wells, these requirements may not be met, and foam propagation is uncertain.
It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (
This article is an extension of a recent study (
Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, which then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities, however, the limit of foam propagation is reached at the lowest velocity tested. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and fg. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen, 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate - probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in ∇P and Sg) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injected rate.