Mahmoudi, Mahdi (RGL Reservoir Management) | Roostaei, Morteza (RGL Reservoir Management) | Fattahpour, Vahidoddin (RGL Reservoir Management) | Sutton, Colby (RGL Reservoir Management) | Fermaniuk, Brent (RGL Reservoir Management) | Zhu, Da (RGL Reservoir Management) | Jung, Heeseok (RGL Reservoir Management) | Li, Jiankuan (University of Alberta) | Sun, Chong (University of Alberta) | Gong, Lu (University of Alberta) | Shuang, Shuo (University of Alberta) | Qiu, Xiaoyong (University of Alberta) | Zeng, Hongbo (University of Alberta) | Luo, Jing-Li (University of Alberta)
Standalone screen has been widely used as sand control solution in oil industries for over a century. Screen plugging and impairments by formation fines, scaling and corrosion cost oil and gas industry significant amount of resources. This study presents a detailed study on the corrosion and plugging of slotted liner, wire wrap screen and mesh screen samples extracted from the field to better understand some of the mechanisms for these poor field performances.
Three types of standalone screen were received from operating wells to study the failure mechanism of the screen and provide recommendations for recompletion. A thorough visual inspection of all screens was performed and documented in this paper. From the results of the visual inspection a certain section of each screen was cut for further detailed microscopic study to better understand the scaling and plugging mechanism, as well as microscopic geometry of the plugged and corroded zone.
The results highlighted the importance of the corrosion in the base pipe on the observed performances. All the studies pointed toward the flow dependence corrosion behavior, and the role of the water cut on the corrosion rate. The wire wrap screens have been in service for less than a year, yet the extensive corrosion led to creation of several holes in the pipe. The study showed the corrosion initiated from inside the pipe. Similarly, the corrosion of the slotted liner samples showed a strong flow dependent corrosion rate, where the corrosion rate on the slot/formation interface was slightly higher. The mesh screen showed very high plugging percentage by formation fines, where a thick film of clay and fine sand covered the space between the mesh and the base pipe. The results indicated that an inappropriate design of the mesh and pore could cause significant plugging.
This paper provides several field examples of the corrosion and plugging of the standalone screens. The results could help engineer to better understand the risk of corrosion and plugging on the standalone screen design. This paper provides some general guidelines for assessing the scaling and corrosion potential at field condition based on the results of the screens studied in the paper.
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).
Moussa, Tamer (King Fahd University of Petroleum and Minerals) | Patil, Shirish (King Fahd University of Petroleum and Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum and Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum and Minerals)
Determination of optimal well locations plays an important role in the efficient recovery of hydrocarbon resources. However, it is a challenging and complex task because it relies on reservoir, and fluid and economic variables that are often nonlinearly correlated. Traditionally, well placement optimization (WPO) has been done through experience and use of quality maps. However, reservoir management teams are beginning to appreciate the use of automatic optimization tools for well placement that will yield the largest financial returns or highest net present value (NPV). In addition, the performance of a reservoir is time and process dependent, therefore well placement decisions cannot be based on static properties alone. On the other hand, well placement optimization requires a large number of simulator runs in an iterative process, and thus several runs to reach the maximum achievable NPV. Therefore, there is a real need for automatic well placement approach that uses highly efficient optimization method, which can improve the result quality, speed of the convergence process to optimal result and thus decrease the time required for computation.
The objective of this work is to determine the optimal well locations in a heavy oil reservoir under production using a novel recovery process, in which steam is generated, in-situ, using thermochemical reactions. Self-adaptive differential evolution (SaDE) and particle swarm optimization (PSO) methods are used as the global optimizer to find the optimal configuration of wells that will yield the highest NPV. Comparison analysis between the two proposed optimization techniques is introduced. The CMG STARS Simulator is utilized in this research to simulate reservoir models with different well configurations.
Comparison of results is made between the NPV achieved by the well configuration proposed by the SaDE and PSO methods. The results show that SaDE performed better than PSO in terms of higher NPV after ten years of production while under in-situ steam injection process using thermochemical reactions. This is the first known application where SaDE and PSO methods are used to optimize well locations in a heavy oil reservoir that is recovered by injecting steam generated in-situ using thermo-chemical reactions. This research shows the importance of well placement optimization in a highly promising and novel heavy oil recovery process. This also is a step forward in the direction to eliminate the CO2 emissions related to thermal recovery processes.
Heavy oil has attracted global attention due to its huge volume of original oil in place. However, there are numerous operation and economic challenges to the recovery of heavy oil due to its high-viscosity and high-density. Thermal recovery methods such as steam injection is viable and commonly used to recover heavy oil and bitumen primarily by viscosity reduction of heavy oil and improving the displacement of the heavy oil. However, there are significant heat losses before the steam reaches the heavy-oil reservoir, in addition to the concerns of high cost and emission of greenhouse gases. One of the promising new heavy-oil recovery approaches is generating steam with nitrogen gas, in-situ, using thermochemical reaction to reduce oil viscosity, improve the mobility ratio and enhance the heavy-oil displacement. Steam and nitrogen are generated, in-situ, by injecting exothermic reactants downhole with the injected water to create heat and enhance reservoir pressure for mobilizing heavy oil. The exothermic reaction is triggered by either increasing downhole temperature or in the presence of a low pH weak acid.
In this research, a numerical study of the novel heavy oil recovery process using in-situ steam and nitrogen generated by thermochemical reactions in field scale is conducted. Various ratios of nitrogen- steam are studied to identify their effect on the recovery efficiency. In-situ Nitrogen-steam ratio generated by thermochemical is optimized to accomplish the maximum achievable net present value (NPV) after ten years of recovery. The CMG STARS simulator is used to simulate reservoir models with different operational parameters.
The results show that the generated heat from in-situ thermochemical reactions was sufficient to reduce the viscosity of heavy oil, while the generated nitrogen gas provided a good heat insulation effect and reduced steam-oil ratio. Thus, higher NPV was achieved than typical conventional steam-only injection method.
This is the first time NPV and all economic parameters are considered to analyze the performance of an in-situ steam and nitrogen generated by thermochemical reaction. This research shows that the recovery of the proposed method is more suitable and economical for the reservoirs which are not viable for conventional steam flooding methods and it is a step forward to eliminate CO2 emissions associated with thermal recovery process.
Heavy oil has attracted global attention due to its huge volume of original oil in place. However, there are numerous operation and economic challenges during the recovery of heavy oil due to its high-viscosity and high-density. Thermal recovery methods such as steam injection is viable and commonly used to recover heavy oil and bitumen primarily by thermally altering oil viscosity and improving the displacement of heavy oil. However, there are significant heat losses before the steam reaches the heavy oil, in addition to the concerns of high cost and emission of greenhouse gases. One of the promising new heavy oil recovery approaches is generating steam, in-situ, using chemical reaction to reduce the oil viscosity, improve the mobility ratio, and enhance the heavy oil displacement.
The objective of this work is to introduce a novel heavy oil recovery process using in-situ steam generated by thermal and chemical reaction and analyze its recovery performance compared with conventional steam injection method from the economic point of view, as well as based on the achieved net present value (NPV) of each technique. Sensitivity analysis of the proposed recovery processes to different operational parameters is introduced. The CMG STARS™ Simulator is used in this work to simulate reservoir models with different operational parameters. The recovery performance of the proposed technique outperformed the conventional steam flooding method and achieved higher NPV after ten years of production.
This is the first time to use NPV and consider all economic parameters to analyze the performance of the developed recovery process of in-situ steam generation by chemical reaction. This research shows that the recovery of the proposed method is economic, and applicable to the reservoirs which are not viable for conventional steam flooding methods and it is a step forward to eliminate CO2 emissions associated with thermal recovery processes.
For thermal in-situ oil sands production, it is conventional to think that an emulsion pipeline remains essentially oil-wet. Ideally, an oil coating distributed on the pipe by the produced water-in-oil emulsion from a well pad is expected to give the needed corrosion protection for the operating life of the pipeline. Practically however, there are conditions under which this ideal scenario becomes no longer feasible, even for low API gravity heavy oil. These parameters affecting protection include but are not limited to water cut, well pad processing, steam cycle phenomena, reservoir characteristics, pipeline operating temperature, partitioning characteristics of the acid gases and their effects on water chemistry and passivation as well as other field operational practices.
From the experience of two case histories at a thermal in-situ oil sands project, this paper elaborates on many of the field parameters and how they influence the integrity of pipeline infrastructure by studying the various corrosion phenomena at play. Corrosion mitigation recommendations for these pipelines will also be presented.
Consideration of corrosion mechanisms in thermal oil recovery facilities should be divided into two categories, conditions with and without microorganisms present; the former is called microbiologically influenced corrosion (MIC). Constant monitoring of these facilities for MIC and controlling them when present is essential to corrosion management. If corrosive microorganisms are present in significant amounts, the probability of failure is high despite the presence of other corrosion mitigating factors including assumptions about oil-wetting, passive scale formation or the efficacy of a chemical inhibition program. This paper deals with non-microbiological corrosion issues and considers the following factors in the context of thermal oil production:
SAGD is an energy-intensive process with large amount of greenhouse gas (GHG) emissions and required water treatment. One option to reduce emissions and water is to use electromagnetic (EM) heating in either the induction (medium frequency) or radio frequency (RF) ranges. Since the early 1970s, research into the use of RF energy to effectively heat heavy oil reservoirs has led to incremental technology advancements. Since 2009, the Effective Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH™, pronounced "easy") consortium suggested a process named similarly that dielectric heating of oil sand is combined with the injection of a solvent such as propane or butane to reduce bitumen viscosity. In January 2012, the mine face test was declared a success and confirmed the ability to generate, propagate, and distribute electromagnetic heat in an oil sand formation. Phase II of ESEIEH™ exploring scaled pilot tests with horizontal antenna in Suncor’s Dover facility is under developing. To distribute electromagnetic heating into the reservoir creation of desiccated zone and its controlled growth is a key. Since the reservoir is an electrically lossy environment, the growth of desiccated zone as a lossless medium helps the electromagnetic fields to propagate deeper into the formation and associated heating is also further developed within the reservoir. The water will continue to vaporize and move away from the "flashed or desiccated zone" at a rate which diminishes with time. Eventually it reaches the equilibrium condition that it cannot grow with given delivered RF power from the radiating antenna. In this study, the desiccated zone extension at its equilibrium is calculated on the basis of this concept to prevent the zone from collapsing. In this process, water should vaporize and leaks into reservoir to create the flow rate normal to the desiccated zone surface that pushes the water back and grow the zone. Another highlight on this study is to provide the solution for RF-heating avoiding the Lambert’s law or plane-wave assumption. Lambert’s law is (only) accurate and valid in guided-microwave structures or when the EM radiating source is far from the receiving load (relative to the wavelength), such as in optical regime or in telecommunication applications. Although, for heating applications, the maximum energy dissipation of RF waves takes place in the near-field region and not in the far-field region, hence, Lambert’s law does not give a correct solution in these cases. As a result of this study minimum required power is a function of reservoir mobility or in-situ water relative permeability. If efficiency of antenna is not high enough and reservoir mobility is greater than 10-3 then the RF power transmission system could not deliver enough energy to grow the desiccated zone.
As a critical input in determining the maximum steam injection pressure, caprock integrity assessment in thermal operations has become increasingly important because of the potential severe consequences of a caprock integrity breach on the environment, safety and project economics. Because of the complex thermo-poro-mechanical coupling of the thermal stimulation process, numerical simulation is required in evaluating caprock integrity.
Thermal stimulation of heavy oil reservoirs significantly alters the pore pressure and in-situ stresses not only in the reservoir, but also in the caprock. Rock mechanical properties also change with temperature, pore pressure, stresses and rock deformation. Accurate characterization of reservoir and caprock mechanical properties and constitutive behavior is critically important in caprock integrity analysis. Through geomechanical and fluid flow coupled simulation of a steam-assisted gravity drainage (SAGD) case using commercially available reservoir simulator and finite element geomechanical simulator, this paper discusses the physical processes that occur in thermal operations, including stress and strain change, rock volume change, and rock failure, in both the reservoir and the caprock. The effects of rock elastic and strength properties, constitutive model, coefficient of thermal expansion, thermally induced pore pressure, and steam injection pressure on reservoir deformation and caprock integrity will be explained through simulation cases.
A noteworthy caprock failure occurred on the Joslyn Steam Assisted Gravity Drainage (SAGD) project in 2006 that continues to have a significant impact on the approval process for future SAGD projects. Two major reports were released by Total E&P Canada Ltd. as operator and Alberta Energy Regulatory (AER), respectively. A number of potential mechanisms were postulated within those studies, but without a definitive resolution. Inclusion of a fractured medium in the assessment of caprock integrity has not been extensively studied for detection of failure modes. The objective of this paper is to explore the effects of existence of discontinuities (e.g. fractures or fissures) in caprock, loading conditions, and steam chamber evolution, on surface heave, joint normal and shear displacements. Different modes of failure under various scenarios are presented for fissured and non-fissured caprocks.
In this paper, a distinct element code was utilized to simulate the possible mechanisms of caprock failure during SAGD operation with various fracture sets in the Clearwater Formation caprock. Three-dimensional numerical models, including caprock and overburden, were simulated under different load conditions to evaluate the impact of steam injection pressure. The lower bound for maximum operating pressure (MOP) was based on the current AER formula and the upper bound was the injection pressure prior to caprock failure. Multiple realizations of fracture network in caprock were executed to reflect various geomechanical and geometrical properties of fractures. The results were compared with a previous study performed with the assumption of a continuum medium for a non-fissured caprock.
For upper bound MOP conditions, the computed maximum vertical displacements at the base of caprock for models assuming 1) no fractures, 2) low fracture intensity, and 3) high fracture intensity were 79, 74 and 68 cm, respectively. It was observed that an increase in fracture intensity results in a reduction in vertical displacement at the base of caprock as well as surface heave. These variations in behavior are significant and illustrate that the assumption of a non-fractured caprock (in caprock integrity studies) may lead to conservative estimates of steam containment and ultimately, underestimation of the risk for caprock failure.
At the base of caprock and under lower bound MOP conditions, a few local shear failure zones occurred above the pressurized zone, while for upper bound MOP conditions, larger zones of both shear and tensile failures were computed. It was also noted that the existence of fractures could cause local shear failure in the caprock, even below AER mandated values of MOP. Lastly, the findings of this study, including geomechanical simulations, uncertainties, and risk associated with evaluating caprock containment of SAGD operations were compared with previous studies.
The results offer significant insight into our geomechanical understanding of the process in order to avoid a potential caprock failure during thermal projects, as unfortunately was experienced in the Joslyn SAGD steam release incident.