Smith, Richard James (Imperial Oil Resources Ltd.) | Meier, Steven W (ExxonMobil Research & Engineering Company) | Adair, Neal Leon (ExxonMobil Upstream Research Co.) | Kushnick, Arnold P (ExxonMobil Research & Engineering Company) | Leonardi, Sergio Adrian (ExxonMobil Upstream Research Co.) | Herbolzheimer, Eric (ExxonMobil Research & Engineering Company) | Yale, David P (ExxonMobil Upstream Research Co.) | Wang, Jianlin (ExxonMobil Upstream Research Co.)
The oil sands of Canada are a rich resource whose extraction faces many challenges. The most common processes for recovering in situ resources (i.e. too deep to mine) involve heating the reservoir to reduce the heavy oil or bitumen viscosity to allow it to flow to wellbores where it can be produced. This paper presents an alternate concept for recovery of these resources that does not require heat to mobilize the bitumen and that is especially well suited to reservoirs that are too thin or too geologically complex for economic thermal recovery.
The process utilizes water injection to "condition?? a reservoir interval sufficiently to relieve the overburden stress on the oil sand and increase its porosity and permeability. Establishing a pressure gradient between a set of injector and producer wells allows the production of a bitumen-sand-water slurry as the pressure gradient established overcomes the friction holding the reservoir sand in place. This produced slurry is then processed at the surface to extract the bitumen and the cleaned tailings are re-injected back into the reservoir to aid in the sweep of the in situ sand, support the overburden, and dispose of the tails.
We have developed a first principles numerical model of the process that fully accounts for fluid flow and sand flow under reservoir conditions to simulate and understand the process. We have also developed a large scale (2 meter diameter sand pack) laboratory system to demonstrate the technical feasibility of the process under reservoir conditions.
The technology is still in the early stages of development, but the laboratory and numerical modeling efforts demonstrate promising technical potential of the process at a field-scale. The ability of the process to work in thinner and more geologically complex reservoirs than other in situ processes, and with lower CO2 and surface footprints than thermal and mining processes, could make this an attractive alternative recovery process for shallow to intermediate depth, in situ bitumen resources.
Hydrogen sulfide (H2S) generated by aquathermolysis—a high-temperature reaction of condensed steam (water) with sulfur-bearing bitumen in the reservoir rock—may increase the risk of sulfide stress cracking (SSC) in cyclically steam stimulated (CSS) wells. In a given field, H2S levels and wellbore conditions vary significantly among wells and so do their SSC-susceptibility. Identifying the SSC-susceptible wells is important in terms of reducing SSC risk by allocating resources and implementing pro-active intervention measures to the SSC-susceptible wells. A comprehensive research program, with a dedicated instrumented CSS well as the centerpiece, has been undertaken by Imperial Oil Resources with the objectives of characterizing H2S evolution in the wellbore and developing a tool for identifying the SSC-susceptible wells. The research includes laboratory and field tests, and statistical, phase behaviour and kinetic modelling. The SSC-susceptible zone for Cold Lake CSS has been established from Cyclic Slow Strain Rate (CSSR) laboratory tests incorporating CSS fluid chemistry, stress-strain environments, casing metallurgy, and variable temperature and H2S partial pressure. A statistical logistic model matches the experimental CSSR data well. The instrumented well data validate the phase behavior model, which in turn explains the measured H2S profile in the wellbore. An aquathermolysis kinetic model has been developed for the instrumented well and validated with data from nine other CSS wells. The research has led to the development of an engineering tool for identifying the wells at the risk of falling into the SSC-susceptible zone.
Hsu, Sheng-Yuan (ExxonMobil Upstream Research) | Searles, Kevin Howard (ExxonMobil Upstream Research) | Liang, Yueming (ExxonMobil Corporation) | Wang, Lei (ExxonMobil Upstream Research) | Dale, Bruce A. (ExxonMobil Upstream Research) | Grueschow, Eric Russell (ExxonMobil Upstream Research) | Spuskanyuk, Alexander (ExxonMobil Upstream Research) | Templeton, Elizabeth (ExxonMobil Upstream Research) | Smith, Richard James (Imperial Oil Resources Ltd.) | Lemoing, Daniel R.J. (ExxonMobil Qatar)
The Cold Lake heavy oil development is located in northeast Alberta, Canada. It began commercial operation in 1985 and uses a thermal recovery process called cyclic steam stimulation (CSS). During steaming cycles, the dilation and re-compaction that occur within the reservoir cause the overburden to deform much like the motion of flexing a thick telephone book. At weak overburden layers, shear slip plane(s) can form due to excessive shear stress overcoming the interlayer cohesion. Over multiple steaming/production cycles, the cyclic flexing and associated shear slip may lead to overburden casing fatigue failures.
In this paper, a multi-scale geomechanics modeling methodology is presented to predict the onset of failure due to CSS-related ultra low cyclic fatigue (ULCF). The modeling methodology consists of: (i) converting geological data into a representative finite element model of a single or multiple CSS pads, (ii) constructing a near-well submodel that includes thermal cement and casing, and (iii) constructing a detailed casing and connection submodel to predict the ULCF life of a pipe body or connection.
To predict the ULCF life of the casing and connection, an algorithm based on the concept of cyclic void growth is incorporated into the submodel. It provides the capability to predict the number of steam cycles to failure using the concepts of demand and capacity. This enables studying the effects of alternative steaming practices on overburden shear slip and casing/connection life.
Based on the learning from the multi-scale modeling, it is found that shear displacements on a shear slip plane can be superimposed using a single-well solution. By applying steaming and production scaling functions, the shear slip can be determined at any location and time. Integration of the single-well solution with ULCF algorithm has facilitated development of a new software tool that can be used to manage CSS operations in Cold Lake.
Bailey, Jeffrey R. (ExxonMobil Upstream Research Co.) | Smith, Richard James (Imperial Oil Resources Ltd.) | Keith, Colum M. (Imperial Oil Resources Ltd.) | Searles, Kevin Howard (ExxonMobil Upstream Research Co.) | Wang, Lei (ExxonMobil Upstream Research Co.)
Cyclic Steam Stimulation (CSS) is a cost-effective means to produce heavy oil at the Cold Lake field in Alberta, Canada. The high viscosity of bitumen is the main obstacle to economic production, but the bitumen viscosity decreases significantly with temperature. Steam is injected at fracturing conditions, resulting in complex interactions of reservoir expansion (dilation) and contraction (recompaction) that propagate stress and strain fields in the overburden.
The mechanical loads on wells resulting from this production process are an important design consideration. To enhance operational integrity, a dedicated passive seismic monitoring well is installed on new development pads to provide early detection of casing failures and possible fracturing of the formation overburden. There is now an installed base of almost 90 such acoustic monitoring wells in the operator's field. With data acquisition of 15 to 30 geophones per system, recording continuously at 2000 or 3000 samples per second, the data management issues for this monitoring network are challenging.
Several classes of acoustic events have been identified, including those due to casing failure, formation heave, near-wellbore cement cracking, and production rod pump background noise, in addition to "Continuous Microseismic Radiation?? (CMR) that resembles harmonic tremors. Most casing failures are detected by observation of singular events. The detection of fracturing of the overburden, which may include the presence of bitumen and/or produced water that has migrated out of zone, is a more complex process that requires distinguishing shear events and CMR events from normal formation heave and other environmental noise.
The operator has stewarded the development of a cost-effective system that includes local pad data acquisition, uploading of selected data to a server with data archiving facilities, and downloading data to dedicated analysts. This paper will present a summary of the data management and processing technologies developed to address the challenge of managing this data-intensive problem.