Using horizontal wells for primary production of heavy oil reservoirs is common in Canada but it is less frequent to employ them for waterflood. As a result, very few papers have been published on this topic. Similarly, numerous publications are available on the use of conventional forecasting methods to evaluate waterflood performances, but very few if any have focused on waterfloods with horizontal wells in heavy oil reservoirs. This is what this paper proposes to do.
The production performances of over twenty horizontal wells from five Canadian heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. Conventional waterflood forecasting methods such as Arps, Yang and logarithm of Water-Oil Ratio (WOR) vs. Cumulative oil production were used and compared. However, the focus of the paper is not only the comparison of the various forecasting methods but also the evaluation of the performances of horizontal well waterfloods in these high oil viscosities.
The Arps method appears difficult to use, especially when there are strong variations in injection rates. By comparison, the Yang and the WOR vs. Cumulative production methods appear more stable. The forecast in cumulative production can vary widely between these methods. Ultimate recovery is expected to vary from a few percent OOIP to over 20%OOIP.
This paper will present the performances of several horizontal waterfloods in heavy oil reservoirs in Canada and compare several waterflood analysis methods. Very few if any paper has been published on this topic thus the information provided will be of interest to engineers who are considering using horizontal wells for waterflood as a follow-up to primary production in heavy oil reservoirs.
Waterflooding in low permeability, fractured and oil-wet carbonate reservoirs yields extremely low oil recovery due to bypassing through fractures and little imbibition into the matrix resulting in a large amount of oil remaining in the reservoir. Gravity-aided gas injection is studied at the lab-scale in this work to enhance oil recovery from fractured reservoirs. The miscibility of the gas with a model oil (decane with naphthenic acid) is varied by enriching the methane with ethane. Mobility of the gas is decreased by incorporating the gas in foam or glycerol-alternating-gas floods. As the miscibility increases, the oil recovery increases, but reaches a plateau above the near-miscible conditions. The foam flood improves oil recovery by diverting gas into the matrix, if the gas is sufficiently soluble in the oil and the gas-oil capillary pressure is sufficiently low. The pressure gradient generated in the fracture by foam helps in the diversion of the gas into the matrix. Glycerol-alternating-gas floods result in minor additional oil recovery over foam floods because the pressure gradients are about the same. These experiments need to be repeated after gas floods (before conducting foam floods). Near-miscible (and miscible) foam floods increased the oil recovery to high values (about 85% OOIP) in core floods and their scale-up to reservoir scale warrants further study.
Kim, Do Hoon (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | New, Peter (Chevron Upstream Europe) | Jackson, Adam C (Chevron Upstream Europe) | Espinosa, David (Chevron Energy Technology Company) | Isbell, Taylor Jordan (Chevron Energy Technology Company) | Poulsen, Anette (Chevron Upstream Europe, Chevron Energy Technology Company) | McKilligan, Derek (Chevron Upstream Europe) | Salman, Mohamad (Chevron Energy Technology Company, University of Houston) | Malik, Taimur (Chevron Energy Technology Company) | Thach, Sophany (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Polymer mixing is often challenging under offshore conditions due to space constraints. A theoretical approach is required to better understand the drivers for polymer hydration and design optimal field mixing systems. We share a novel theoretical approach to gain insights into the energy required for optimum mixing of novel liquid polymers. We present a new parameter, "Specific Mixing Energy" that is measured under both lab and field mixing conditions and can be used to scale-up laboratory mixing. We developed a simplified laboratory mixing process for novel liquid polymer that provided acceptable viscosity yield, filtration ratio (FR), and non-plugging behavior during injectivity tests in a surrogate core. A FR less than 1.5 using a 1.2 μm filter at 1 bar was considered acceptable for inverted polymer quality. We developed estimates for specific mixing energy required for lab polymer inversion to achieve these stringent FR standards and comparable viscosity yield. We then conducted yard trials with both single-stage and dual-stage mixing of the novel liquid polymer and developed correlations for specific mixing energy under dynamic conditions. Based upon the results of lab and yard trials, we tested the approach in a field injectivity test. The FR and viscosity were also correlated to a specific mixing energy to establish the desired operating window range from laboratory to field-scale applications. Such information can be used to enhance EOR applications using liquid polymers in offshore environments.
AlSofi, Abdulkareem M. (Saudi Aramco) | Wang, Jinxun (Saudi Aramco) | AlBoqmi, Abdullah M. (Saudi Aramco) | AlOtaibi, Mohammed B. (Saudi Aramco) | Ayirala, Subhash C. (Saudi Aramco) | AlYousef, Ali A. (Saudi Aramco)
The synergy between various enhanced-oil-recovery (EOR) processes has always been raised as a potential optimization route for achieving a more-economic and more-effective EOR application. In this study, we investigate the possible synergy between polymer and smartwater flooding for viscous-oil recovery in carbonates. Although the potential for such synergy has been suggested and researched in the literature, we investigate this possibility in a more-realistic framework: part of the development of an EOR portfolio for a slightly viscous Arabian heavy-oil reservoir. In this work, we study the possible synergy between smartwater and polymer flooding by performing rheological, electrokinetic potential (ζ-potential), contact-angle, interfacial tension (IFT), and recovery experiments.
Rheological tests, as expected, demonstrated the possibility of achieving the same target viscosity at lower polymer concentrations. With smartwater, the polymer concentration required to achieve a target viscosity of 11 mPas was found to be one-third lower than that with normal high-salinity injection water. Electrokinetic-potential and contact-angle results demonstrated that polymer presence has negligible to slightly favorable effect on wettability alteration induced by smartwater. On synthetic calcite surfaces, polymer showed negligible effect, whereas on reservoir-rock surfaces, polymer resulted in further reduction in contact angles beyond that obtained with smartwater.
Coreflooding experiments conducted at reservoir conditions with finite smartwater/polymer slugs—besides yielding comparable performance to surfactant/polymer flooding—demonstrated the enhanced performance of smartwater/polymer compared with either of these individual processes. A combined smartwater/polymer process was able to recover substantial additional oil—6.5 to 9.9% original-oil-in-core (OOIC)—above that obtained with either of the two processes when applied independently. Ultimate recoveries from the application of smartwater/polymer (70% OOIC) were quite comparable to, and actually slightly higher than, that of surfactant/polymer (67% OOIC). However, in terms of the remaining oil in core (ROIC) after polymer flooding, both processes (smartwater/polymer and surfactant/polymer) exhibited quite similar incremental recoveries of 20.6 and 20.5% OOIC, respectively.
The results of this work clearly demonstrated the potential synergy between smartwater and polymer flooding—beyond that of the well-established polymer-viscosity enhancement—for a realistic scenario. The additive effect of smartwater was successfully shown to combine with polymer to increase oil recovery, in addition to lowering the polymer concentration. This favorable synergy will reduce chemical-consumption costs and improve recovery to enhance EOR-project economics.
Seright, Randall S. (New Mexico Institute of Mining and Technology) | Wang, Dongmei (University of North Dakota) | Lerner, Nolan (Cona Resources Limited) | Nguyen, Ahn (Cona Resources Limited) | Sabid, Jason (Cona Resources Limited) | Tochor, Ron (Cona Resources Limited)
This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada’s Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.
Enhanced Oil Recovery (EOR) has been utilized in Trinidad and Tobago for over 50 years. Most projects so far have focused on thermal as well as gas injection along with the more conventional waterfloods. In spite of that, recovery factors are still relatively low and the country's oil production has been declining for some time. Surprisingly, given the progress in chemical EOR and in particular polymer flooding in the last 10 years, these processes have not been used in Trinidad and we suggest that it might be time to consider their application. Similarly, foam has been used extensively worldwide to improve performances of gas and steam injection but has not yet been used in the country.
The situation of EOR in Trinidad will be first reviewed along with the characteristics of the main reservoirs. Then the potential for the application of chemical-based EOR methods such as polymer, surfactant and foams will be studied by comparing the characteristics of Trinidad's reservoirs to others worldwide which have seen the applications of chemical-based EOR methods.
This review and screening suggests that there is no technical barrier to the application of all these EOR methods in Trinidad. Most reservoirs produce heavy oil and are heavily faulted, but polymer injection has been widely applied in heavy oil reservoirs as well as in faulted reservoirs before, and suitable examples will be provided in the paper. Similarly, these characteristics do not present any specific difficulty for foam-enhanced gas or steam injection. The main issue appears to be the identification of suitable water sources for the projects.
This paper proposes a new look at EOR opportunities in Trinidad using conventional methods which have not been used in the country. This will help reservoir engineers who are considering such applications in the country and hopefully will eventually result in an increase in the oil production in the future.
ABSTRACT: The main goal of this research was to investigate the risk of caprock failure due to the SAGDOX process, a hybrid steam and in-situ combustion recovery process for oil sands. A temperature dependency extension to the linear and non-linear constitutive models was developed and implemented in the GEOSIM software. The analysis has shown that there is no increased risk of caprock failure for SAGDOX process compared to SAGD. The study has shown that the overlying Wabiskaw formation experiences shear failure during both SAGD and SAGDOX due to its low initial cohesion, friction angle and proximity to pressure and temperature front, although the failure was mainly driven by pressure propagation. However, Clearwater shale above Wabiskaw can still provide proper zonal isolation to the steam/combustion chamber under SAGDOX operating conditions. Uncertainty in the analysis is due mainly to the sparse nature of geomechanical properties data for the oil sand reservoir and the caprock formations, especially at temperatures over 200 C.
1.1 The SAGDOX process
Nexen Energy ULC (Nexen) has been evaluating SAGDOX - a post SAGD oxidation process (Kerr, 2012; Jonasson and Kerr 2013) - to improve the recovery and project economics of its Long Lake SAGD operation. SAGDOX is meant to be used after several years of SAGD operations when the bitumen between two SAGD well-pairs is mobile. In SAGDOX process (applied to a row of parallel well pairs) oxygen is coinjected with steam in every other SAGD injector well and starts an oxidation process by reacting with residual oil around the injection well. At this point the SAGD production well below the oxygen-steam injector is shut in and steam along with oxygen and combustion gasses fill the steam chamber voidage and push hot bitumen towards the neighbouring SAGD well-pair. The neighbour injection well is also shut-in and could be converted to a producer if need be. Various other well arrangements have been considered including those with vertical injection wells and infill horizontal production wells. Since oxygen is co-injected with steam, very high oxidation temperature of a pure combustion process are not generated as steam carries a large portion of the heat of combustion away from reaction front and temperatures are thereby moderated. Nonetheless, temperatures in the range of 400-600 deg C are expected in the oil sand zone. The high temperature combustion front where the oxidation reactions are active moves away from the oxygen injection wells as the residual oil left behind after steam displacement is consumed. The high temperature reaction zone has a tendency to move upward towards the cap rock under the influence of gravitational forces.
ABSTRACT: This paper investigates the potential of using heating or cooling to induce shear or tensile failure of the shales present in low-quality oil sands of Alberta and thus improve vertical communication and recovery. Several methods were considered and explored by conceptual simulations, in a setting representative of Nexen Energy ULC Long Lake reservoir. Various scenarios were simulated using a coupled thermal reservoir and geomechanical modeling software (GEOSIM). In order to capture the relevant physics, significant extensions to the software were required, for modeling cryogenic cooling and thermal dependencies of properties. The main findings of the study are:
- Electric heating using the SAGD injector well can induce shear failure in shales close to it. It also creates a shear failure region around the injector and it could be considered as a modification of the start-up strategy.
- Modeling of cryogenic cooling requires capturing several ice formation effects, which have a strong effect on stresses and failure. Cryogenic cooling directly in the shale predicted progressive shear failure to a considerable distance from the injector. 2-D simulations of cooling the SAGD injector show that the horizontal stresses can be considerably reduced and will favor vertical fractures
- Hydraulic fracturing after a sufficient cooling period appears to be a feasible process which can be carried out with significantly reduced injection pressures, comparable to MOP (maximum operating pressure).
As the in-situ oil sands development in Alberta matures, projects in lower quality reservoirs must be considered. Poor quality sands often contain interbedded shales with areal extent which can significantly impair vertical communication and drastically reduce recovery in conventional SAGD or related hybrid processes. Several methods have been envisioned to provide vertical communication through the shales, but none of these have been proven in the field so far. Of these, the use of multi-stage fracturing technology (Saeedi and Settari, 2016) is not always applicable because the stress regime may not favor vertical fractures. A desirable method would be one that is feasible to implement at startup time, does not require excessive pressures, does not endanger caprock integrity and provides sufficient improvement in vertical communication. In this research, we have considered and evaluated several techniques, which are based on geomechanical principles:
a) Local heating at shale locations. The idea is to create sufficient increase in horizontal stress to induce shear failure and increase in vertical permeability across the barrier. The implementation could be via induction or microwave electric heating, or one can also consider use of resistive heating elements in the wells with heat transfer into the formation mainly by conduction.
b) Local cooling (using cryogenic technology). If it is possible to selectively cool the shale, tensile fracturing could develop. This mechanism is believed to exist also on fracture face in waterflood induced fracturing and has been quantified by simulation (Tran et al., 2013).
Polymer flooding has increasingly been considered for heavy oil recovery applications. This has been encouraged by positive results from field applications at e.g. Pelican Lake and Tamaredjo and lab experiments showing that highly efficient recovery can be obtained at mobility ratios far from unity. Improved understanding of the mobilization process will increase process efficiency. Here we have used x-ray visualization to study sweep efficiency by an associative polymer at adverse mobility ratio in 2D flow.
The x-ray scanner provides visual information on the development of fingers and saturation changes during the flooding process. Sweep efficiency was evaluated in two dimensional flow using a 30x30x2 cm slab of Bentheimer outcrop sandstone. A 540 cP crude oil was first displaced by water, then by 1000 ppm of a PAM-based associative polymer in a low salinity brine. Associative polymers have a potential for intermediate heavy oil/heavy oil applications due to favorable salt and shear tolerance, thermo-thickening properties and high resistance factors (RF) obtained in porous media due to hydrophobic interactions.
Oil displacement by water at adverse mobility ratio is characterized by frontal instability and fingering of the water phase through the oil phase, leading to early water breakthrough and poor sweep efficiency. The details of this process is not revealed in typical core floods as pressure and production data can be fitted to a multitude of recovery scenarios for an unstable displacement. The x-ray visualization showed that the water flood was highly unstable with numerous thin fingers forming. As expected, an early water breakthrough was observed at about 0.07 PV injected. After water breakthrough additional oil recovery was primarily inefficient sweep between existing fingers. Polymer injection initiated at a stable, high water cut (97 - 98 %) was highly efficient, recovering 21 % OOIP over 0.7 PV injected. Production data showed a strong reduction in water cut suggesting formation of an oil bank. Saturation images confirmed this, and additionally revealed that the oil bank was formed by a combined polymer sweep between fingers and by expansion of established fingers in the first 2/3 of the slab, leading to accumulation toward the production well. However, the polymer flood was unstable, with no clear polymer bank formed in contrast to typical 2D polymer floods at lower mobility ratio.
This is to our knowledge the first 2D flow experiment of oil mobilization by associative polymers. It shows that the polymer is highly efficient in accelerating the production in a tertiary flood where water is inefficiently flowing predominantly in an established water finger pattern. Combining visualization of 2D flow with pressure and production data leads to better insight into the mechanism of oil mobilization by associating polymer.
Vik, Bartek (Uni Research, CIPR) | Kedir, Abduljelil (Uni Research, CIPR) | Kippe, Vegard (Statoil ASA) | Sandengen, Kristian (Statoil ASA) | Skauge, Tormod (Uni Research, CIPR) | Solbakken, Jonas (Uni Research, CIPR) | Zhu, Dingwei (Uni Research, CIPR)
Polymer injection for viscous oil displacement has proven effective and gained interest in the recent years. The two general types of EOR polymers available for field applications, synthetic and biological, display different rheological properties during flow in porous media. In this paper, the impact of rheology on viscous oil displacement efficiency and front stability is investigated in laboratory flow experiments monitored by X-ray.
Displacement experiments of crude oil (~500cP) were performed on large Bentheimer rock slab samples (30×30cm) by secondary injection of viscous solutions with different rheological properties.
Specifically, stabilization of the aqueous front by Newtonian (glycerol and shear degraded HPAM) relative to shear thinning (Xanthan) and shear thickening (HPAM) fluids was investigated.
An X-ray scanner monitored the displacement processes, providing 2D information about fluid saturations and distributions. The experiments followed near identical procedures and conditions in terms of rock properties, fluxes, pressure gradients, oil viscosity and wettability.
Secondary mode injections of HPAM, shear-degraded HPAM, xanthan and glycerol solutions showed significant differences in displacement stability and recovery efficiency. It should be noted that concentrations of the chemicals were adjusted to yield comparable viscosity at a typical average flood velocity and shear rate.
The viscoelastic HPAM injection provided the most stable and efficient displacement of the viscous crude oil. However, when the viscoelastic shear-thickening properties were reduced by pre-shearing the polymer, the displacement was more unstable and comparable to the behavior of the Newtonian glycerol solution.
Contrary to the synthetic HPAM, xanthan exhibits shear thinning behavior in porous media. Displacement by xanthan solution showed pronounced viscous fingering with a correspondingly early water breakthrough.
These findings show that at adverse mobility ratio, rheological properties in terms of flux dependent viscosity lead to significant differences in stabilization of displacement fronts. Different effective viscosities should arise from the flux contrasts in an unstable front.
The observed favorable "viscoelastic effect", i.e. highest efficiency for the viscoelastic HPAM solution, is not linked to reduction in the local Sor. We rather propose that it stems from increased effective fluid viscosity, i.e. shear thickening, in the high flux paths.
This study demonstrates that rheological properties, i.e. shear thinning, shear thickening and Newtonian behavior largely impact front stability at adverse mobility ratio in laboratory scale experiments. Shear thickening fluids were shown to stabilize fronts more effectively than the other fluids. X-ray visualization provides an understanding of oil recovery at these conditions revealing information not obtained by pressure or production data.