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.
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.
AlKaaoud, Hassan (KOC) | Singh, Bharat (Kuwait Oil Company) | Marston, David (Golder Associates Ltd.) | McQuaid, James (Suncor Energy Inc) | Devon, John (Devon Mining Geology Consulting LLC) | Preene, Martin (Preene Groundwater Consulting) | Hornbrook, John (DeGolyer and MacNaughton Inc) | Pope, Gary (University of Texas at Austin)
This paper discusses the scope for a broader application of a surface-mining approach and builds on the results of a conceptual study that examined the possibility of surface mining the viscous crude oil of the Ratqa Lower Fars (RQLF) reservoir in northern Kuwait. The study findings indicate that a large rate of crude oil might be profitably and sustainably produced for many decades through a surface-mining approach. Introduction The oil industry's challenge has always been the improvement of recovery efficiency using supplementary or unconventional ways of extracting hydrocarbons, as with the various techniques (thermal, gas injection, and chemical) of enhanced oil recovery (EOR). As a result of the physical limits of reservoir-engineering exploitation schemes using drilled wells, recovery predictions are usually presented as a broad range rather than a precise number, and the typical recovery methods often leave a great deal of oil behind. With a mining approach, the upper limits of a reservoir's production rate are no longer largely dependent on inherent properties such as pressure and permeability, but instead on the equipment used and the rate at which the reservoir, along with the hydrocarbon resource, can be excavated.
Steam-assisted-gravity-drainage (SAGD) processes become effective only after thermal and hydraulic communication between an injection and production well has been established during the startup operation of the well pair. Conventional steam-circulation startup operations typically take 2 to 3 months to achieve interwell communication, but reductions in the startup time can have a favorable impact on project economics. Enhancement of interwell permeability using fluid-injection (water, or steam, or solvent) strategies to promote geomechanical dilation of the oil sands has been proposed as a startup technique. These fluid-injection processes will produce complex interactions of thermal, geomechanical, and multiple-phase flow behavior in the interwell formation region. Understanding better the role that these interactions play in establishing well-pair communication will provide opportunities to improve SAGD recovery performance.
A triaxial experimental program has been designed and executed to explore whether cold-water injection would be sufficient to induce enhancements in effective permeability to water from geomechanical dilation mechanisms. Sample preparation techniques were modified to allow the preparation of reconstituted, very dense water-wet/bitumen sand specimens with different fluid saturations and almost identical porosities. Reclaimed/cleaned tailings sand from oil-sands mining operations was used to prepare artificial specimens, which are representative of McMurray Formation oil sands. A water-wet or bitumen sand core plug was then tested in an environmental chamber to simulate reservoir boundary conditions in terms of stress state, temperature, and pore pressure. A set of experiments was carried out in a triaxial cell under either initial isotropic or initial anisotropic stress state. Experimental results highlight the promising potential to dramatically enhance effective permeability to water and porosity in the dilated zone using cold-water injection at modest levels of stress anisotropy. The experimental results also provide support for the development of numerical models used in predicting SAGD startup performance and proactive utilization of the dilation as startup process for in-situ oil-sands development.
Thermal recovery methods, in particular technology based on steam injection, are used extensively around the world for heavy oil and bitumen production. Because of the unconsolidated nature of the majority of such deposits, sand control is required. Design effectiveness of sand control depends on the reservoir type, production technology and operational practices. The industry is facing many challenges such as low oil prices, tight environmental regulations, the need to lower risks while assuring well integrity and longevity and project economics. All of that requires special technical solutions for thermal well design, including sand control.
The paper provides an overview of sand control for thermal heavy oil and bitumen production operations, factors affecting sand control design for thermal projects, sand control devices and industry trends. Laboratory observations and field data are discussed. The impact of steam on different quality heavy oil and bitumen deposits in relation to sand control is discussed in detail. Efficient sand control design for thermal production operations requires a multidisciplinary approach and is an integral part of the well longevity and project economics. Better understanding of the impact of reservoir quality, thermal formation damage and operational practices on well performance is required to assure success of a thermal project.
Shear wave technology has had a remarkably consistent presence in the Canadian exploration community for almost 40 years. Although publications from the earliest days are sparse, Unocal and CGG were conducting some of the earliest shear-wave experiments in Canada (Omnes, 1978). Since the initiation of the CREWES Project at the University of Calgary in 1988, P-S converted waves have been acquired, processed and interpreted by many exploration companies for more than 25 years, so there is a fair amount of experience in the application of P-S converted waves to land data in the Calgary geophysical community compared to elsewhere in the world. The quality of acquisition, processing and interpretation has steadily improved over that time and the number of geophysicists who are familiar with the use of shear waves in exploration has gradually increased. Nevertheless, it would be an exaggeration to say that multicomponent exploration is widely established in Canada. Some individuals within some companies use it to gain value in their exploration effort.
Several recent examples of adding value with converted waves have primarily been applications to heavy oil in NE Alberta. Mayer et al. (2014) have demonstrated that joint prestack PP-PS inversion produced the best estimates of Pimpedance, S-impedance and density, allowing for excellent reservoir characterization of the Athabasca oil sands reservoir. The zone of interest is the unconsolidated sands of the Lower Cretaceous McMurray Formation reservoir within which the bitumen oil sands reside. Limited angles of incidence are available in the data because of a large velocity increase at the Paleozoic immediately below the McMurray. As a result, density could not be directly estimated using AVO inversion, but it was successfully estimated from the joint PP-PS inversion. Neural network analysis that used the PP and PS PSTM volumes, attributes from the PP and PS AVO analysis and attributes from the PP-PS prestack inversion as inputs further improved the resolution of the results. Figure 1 shows the result of density inversion with neural network analysis. This density inversion indicates the existence of upper and lower sands, which is also indicated by the wells, however there is a transition from bitumen to water within the sands that is not indicated by density.
Steam injection (including cyclic steam and SAGD) has long been recognized as the favored recovery method for heavy oil, with applications in many fields around the world in particular in California and Canada. More recently, polymer flooding has also become a relatively well accepted method to increase production and recovery in heavy oil fields. Numerous successful pilots have been reported these last few years and field expansions are currently ongoing in Canada, Oman, China and Albania for instance but surprisingly enough, there has been to the best of the author's knowledge no such application in the US. Both steam and polymer injection have their advantages and their limitations and simple screening criteria have been developed by several authors, however there has never been a detailed comparison of the two methods and this is what this paper proposes to do. The pros and cons of both steam injection and polymer flood are reviewed in light of fundamentals and field experience: reservoir depth, thickness, oil viscosity, expected recovery, water usage and economics of both processes (in particular capital requirements) are all addressed.
SUMMARY: In general, geomechanical works compare evolving in-situ stress conditions with rock’s mechanical strength. Therefore, a basic geomechanical work program consists of defining the original in-situ stress condition, characterizing the rock structure and deformation/strength properties and finally, simulating the dynamical stress conditions after an engineering disturbance is introduced to rock formations which has otherwise reached equilibrium in the geological history.
In many situations, heavy oil production takes place in relatively shallow, weakly- or un-consolidated and/or geologically young rock formations. In-situ stress measurements in the field and laboratory tests on the core samples in these unique situations require special attention to principles and details. Moreover, heavy oil production often requires stimulation by injecting stimulating materials which may be at high pressures and/or high temperatures. Nonlinear coupling between the thermo-hydro-mechanical (THM) mechanisms become significant and must be adequately accounted for. All these unique challenges demand special QC/QA measures in carrying out the geomechanical works. This is the focus of the present paper. These measures are derived from experience in over 1,000 projects/tests and also after a peer review of relevant published works in the industry. Details to be covered include: use of multiple interpretation methods, real-time analysis and openhole in a mini-frac test; use of whole cores, drained condition, slow strain rates and/or heating rates in laboratory tests. It is hoped that this paper will provide a common guidance for the service providers in carrying out their geomechanical works or for the operators in managing similar projects.
Geomechanics has become increasingly important in heavy oil development. It is both a necessity to protect reservoir containment integrity and an opportunity to enhance reservoir production. Heavy oil development requires stimulation in order to achieve a high reservoir recovery factor. The stimulation is carried out by injecting steam and other stimulating materials into the reservoir. The pressure and/or temperature disturbance to the reservoir causes its deformation and impacts the caprock above the reservoir.