Zhaoqi Fan* and Daoyong Yang, University of Regina, and Xiaoli Li, University of Kansas Summary Cold heavy-oil production with sand (CHOPS) has been one of the major recovery processes for developing unconsolidated heavy-oil reservoirs by taking advantage of sand production and foamy-oil flow. However, effective characterization and accurate prediction of sand production is still a challenge. In this work, a pressure-gradient-based sand-failure criterion is proposed for quantifying sand production and characterizing wormhole propagation. The criterion was then extended to a grid scale within a wormhole because the pressure gradient is constant at either a pore scale or a grid scale. This was a confirmation that the proposed sandfailure criterion can be used to characterize the sand production in a CHOPS process. Introduction In a heavy-oil reservoir, the sand flux along with the oil flowing into wells has been proved to surprisingly stimulate oil production (Smith 1988). With the advance of progressing-cavity pumps that enable the mixture of oil and sand to flow effectively, CHOPS has been extensively applied to the primary development of unconsolidated heavy-oil reservoirs in western Canada (Huang et al. 1998; Tremblay et al. 1999; Han et al. 2007; Sharifi Haddad and Gates 2015). The CHOPS wells can be found in Lloydminster Field, Provost Field in the Cold Lake Oil Sands Area, Lindbergh Field, Elk Point Field, Frog Lake Field, and in China and Kuwait (Huang et al. 1998; Dusseault 2002; Meza Diaz et al. 2003; Du et al. 2009; Sanyal and Al-Sammak 2011). The CHOPS process can be considered as an effective pretreatment for heavy-oil reservoirs before traditional thermal enhanced-oil-recovery (EOR) techniques and solvent-based injection methods because of the propagation of the wormhole network (Shokri and Babadagli 2012). Most of the sand is commonly produced during the first several months of a CHOPS well life, and the oil-production peak is usually later than the sand-production peak because of the coupling influences of sand production together with pressure depletion (Huang et al. 1998). Physically, high-permeability channels (i.e., wormholes) and foamy-oil flow are considered to be the main mechanisms dominating the CHOPS processes (Huang et al. 1998; Wang and Chen 2004; Tremblay 2005).
A pressure-gradient-based sand failure criterion has been proposed and validated to quantitatively determine the sand production and then characterize the corresponding wormhole growth and its propagations during cold heavy oil production with sand (CHOPS) processes. The new sand failure criterion was firstly developed at a pore-scale by analyzing the mechanical balance around a throat. To simplify the mechanical analysis, a pseudo-interaction force between a failed throat and the rest was proposed to comprehensively and implicitly represent the potential contribution of cementation and geomechanical stresses to fluidization of sand particles. As such, the mechanical balance was mathematically expressed by use of the pressure gradient, the pseudo-interaction force, and the friction caused by the mobilization of sand particles. Then, the sand failure criterion at the pore-scale was achieved and further extended to a grid-scale since the pressure gradient, a key factor dominating the sand production, is constant at either a pore-scale or a grid-scale within wormholes. With the bottomhole pressure as input constraints, the newly proposed sand failure criterion has been validated by history matching production profiles (i.e., cumulative oil production, cumulative gas production, and cumulative sand production) and wormhole propagations of laboratory sand production experiments in the literature. The new sand failure criterion has also been successfully applied to quantify the sand production and then characterize the wormhole propagations of a CHOPS well in the Cold Lake field, Canada. Good agreements have been found from history matching both the experimental measurements and field observations, confirming that the newly proposed sand failure criterion can be used to reproduce the multiphase flow under CHOPS conditions. It is found that both the sand failure and slurry flow contribute to the continuously observed sand production. According to the experimental measurements, the history-matched pressure distribution indicates that the wormhole propagation greatly depends on the magnitude of the breakdown pressure gradient. It is shown from the generated wormhole propagations that continuous sand production may cause heterogeneity no matter whether the original formation is homogeneous or heterogeneous. In addition, the newly proposed sand failure criterion is convenient to be incorporated with any numerical reservoir simulator and thus to be useful for field cases since only a few parameters are required to be inversely determined.
Imbibition of water into the shale matrix is known as the primary reason for inefficient water recovery after hydraulic fracturing treatments. The hydration of clay minerals may induce microfractures in clay-rich shale samples. The increased porosity and permeability due to induced microfractures has been considered to be partly responsible for 1) excessive water uptake of gas shales, and 2) increase in hydrocarbon production rate after prolonged shut-in periods. To test this hypothesis, it is necessary to measure imbibition-induced strain and stress under representative laboratory conditions. In this study, we conduct laboratory tests to 1) measure the strain and stress induced by water imbibition in gas shales and 2) investigate the effect of confining load on the rate of water imbibition. We conduct a three-phase study on rock samples from the Horn River Basin (HRB) and the Duvernay (DUV) Formation, located in the Western Canadian Sedimentary Basin.
Particle-size distribution (PSD) is a list of values that defines the relative amount of particles present according to the size in a sample. The PSD of the McMurray Formation sediments characterizes rock granulometry and is a fundamental indicator of the nature of the sediment. The size distribution of the component solid particles in the McMurray Formation sediments relates to their porosity; volume of water and bitumen contained within the pore space; and the depositional environment, including lithological association, stratigraphy, areal distribution, and associated physical processes. PSD is known to be a significant factor for evaluating bitumen recovery from an oil-sand mine. This is because presence of fines (evaluated by PSD analysis) affects the hot-water-separation process and processing-plant recovery prediction and provides grade control. Presence of more fines translates into lower recovery from commercial oil-sand processing. In this study, we investigate whether the PSD should be also considered a critical parameter for evaluation and estimation of permeability of an oil-sand reservoir. We show, by use of the data from Cenovus Energy’s Telephone Lake lease, that there is a strong relationship between permeability and PSD data. We also show that the information provided by the PSDs for permeability prediction is more significant than that inferred from a simple porosity/permeability relationship. Subsequently, we comment on permeability modeling by use of PSD data and list the techniques available for cleaning and modeling of multivariate PSDs. We document a methodology for modeling of PSDs and provide a work flow for incorporating these data in improved understanding and modeling of permeability and its distribution.
Mature water floods with high-permeability sands and medium-gravity oil are prime candidates for enhanced oil recovery (EOR) methods. We examined actual field results from three reservoirs. The simulation models were history matched on waterflooding and polymer flooding. Forecasts were performed on waterflooding and polymer flooding as well as gel treatments. Results indicated that polymer flooding resulted in a 5 to 8% incremental recovery factor over water flooding, while gel treatments resulted in a 2 to 4% incremental when applied separately. However, when gel treatments were performed immediately prior to polymer flooding, simulation showed the incremental recovery was much higher at 10 to 15%. In other words, there was a large synergistic effect of gels with polymers.
As seen from long-term production data, interwell tracer analysis, pressure pulse tests and communication analysis, many waterfloods develop preferred water channels due to high-permeability thief regions and or waterflood-induced fracturing. These thief regions/channels sometimes cycle large volumes of water from injectors to producers on waterfloods with very high water cuts. These thief regions/channels also can significantly affect the chemical EOR process. Therefore, it is critically important to understand flow mechanisms in the reservoir and then, in some cases, take corrective action before tertiary EOR is implemented.
Permanently plugging these water channels using gel has some significant impacts on improving chemical EOR efficiency and waterflood efficiency. The synergistic effect of the combined treatment significantly improves chemical EOR economics by reducing chemical demand, increasing oil production, decreasing water production and increasing volumetric sweep.
Cold heavy-oil production with sand (CHOPS) is a nonthermalheavy-oil-recovery technique used primarily in the heavy-oil belt in easternAlberta, Canada, and western Saskatchewan, Canada. Under CHOPS, typicalrecovery factors are between 5 and 15%, with the average being less than 10%.This leaves approximately 90% of the oil in the ground after the processbecomes uneconomic, making CHOPS wells and fields prime candidates forenhanced-oil-recovery (EOR) follow-up process field optimization. CHOPS wellsshow an enhancement in production rates compared with conventional primaryproduction, which is explained by the formation of high-permeability channelsknown as wormholes. The formation of wormholes has been shown to exist inlaboratory experiments as well as field experiments conducted with fluoresceindyes. The major mechanisms for CHOPS production are foamy oil flow, sandfailure (or fluidization), and sand production. Foamy oil flow aids inmobilizing sand and reservoir fluids, leading to the formation of wormholes.Foamy oil behavior cannot be effectively modeled by conventionalpressure/volume/temperature (PVT) behavior. Here, a new well/wormhole model forCHOPS is proposed. The well/wormhole model uses a kinetic model to deal withfoamy oil behavior, and sand is mobilized because of sand failure determined bya minimum fluidization velocity. The individual wormholes are modeled in asimulator as an extension of a production well. The model grows thewell/wormhole dynamically within the reservoir according to a growth criterionset by the fluidization velocity of sand along the existing well/wormhole. Ifthe growth criterion is satisfied, the wormhole extends in the appropriatedirection; otherwise, production continues from the existing well/wormholeuntil the criterion is met. The proposed model incorporates sand production andreproduces the general production behavior of a typical CHOPS well.
Lerner, Nolan (Northern Blizzard Resources Incorporated) | Schaab, Brent (Bellatrix Exploration Limited) | Garcia, Juan (Petrominerales Limited) | Bianco, Dan (PennWest Exploration) | Thomas, Scott (PennWest Exploration) | Thompson, Jason (Legacy Oil & Gas Incorporated) | Hollan, Jeremy (Packers Plus Energy Services)
This paper will detail the technological evolution of drilling and completion practices used to optimize the economic development of the Slave Point carbonate platform, specifically in the Evi and Otter fields in northern Alberta, Canada. The Slave Point platform was initially targeted for conventional production by means of vertical wells in the early 1980s. Success was marginal because of the unpredictability of localized porosity development. As a result, the full-scale commercial development of this resource was deemed uneconomic because of poor reservoir quality. More recently, however, horizontal-drilling and multistage-fracturing technology has allowed operators to open up lower-porosity horizons to improve flow capacity, to improve recoveries, and to allow for commercial development from zones previously deemed uneconomic. The Slave Point has a greater thickness and is less permeable than other tight-rock plays in Alberta, such as the Cardium and Viking. It produces high-quality, light oil with low water- and solution- gas-production rates. Despite high estimates of original oil in place (OIP) of approximately 3 to 10 million bbl per section, horizontal-well rates are still challenged because of the lower permeability through the pay section. In this regard, the continued deployment of innovation and technology has been critical in improving well-production performance, compressing project costs, and ultimately optimizing project economics. The focus of this paper is solely on one of the major Slave Point operators who has drilled 49 horizontal wells that account for 200 000 m (656,000 ft) drilled and 1,350 fracture stages in the Evi and Otter Slave Point fields since 2008. This operator has continually deployed advancing technologies to improve project economics. The information will be presented in terms of the influence of technology on well design, the optimization and deployment of the various technologies, and the demonstrated improvement on productivity and reserves recovery. The discussion will focus on three development phases that highlight the progression from vertical to horizontal technology:
The case studies presented will demonstrate clearly the production impact from the use and application of these technologies. The methods and lessons learned through the use of DLs, openhole junctures, and openhole multistage systems can be applied to other unconventional formations.
Nygaard, Runar (Missouri University of Science and Technology) | Salehi, Saeed (University of Louisiana at Lafayette) | Weideman, Benjamin (Missouri University of Science and Technology) | Lavoie, Robert Guy (RPS Energy Canada)
The most viable options for permanent removal of carbon dioxide (CO2) from the atmosphere include large-scale injection of CO2 from stationary sources, such as coal-fired power plants and heavy-oil production, into brine-filled formations. One of the main risks identified with storing CO2 in the subsurface is the potential for leakage through existing wells penetrating the caprock. The wellbore system has several components that can fail and create leakage pathways, including type and placement of wellbore casing and cements, completion method, abandonment, and wellbore expansion or contraction by changes in temperature and pressure. Of the 1,000 wells in the study area near Wabamun Lake, Alberta, 95 wells penetrated the immediate caprock above the proposed Nisku injection formation and were identified as potential leakage pathways. The leakage risk of these wells was evaluated on the basis of knowledge of the well design, current well status, and historical regulations in the area. Only four wells, for the subset of 27 wells studied, were identified as requiring workover, which was less of a problem than anticipated. To evaluate the risk of creating leakage pathways by thermal and pressure changes caused by CO2 injection, a 3D finite-element model was built by use of poroelastoplastic material models for cement and formation. Multistage simulations for casing/cement and cement/ formation interactions with temperature-enabled elements were conducted. A parametric study of cement properties was conducted to investigate cement design and its mechanical properties for injection wells. The simulation results indicated that thermal cooling might reduce near-wellbore stresses, which would increase the risk of integrity loss in casing/cement and cement/formation. The parametric study revealed that the risk of debonding and tensile failure would increase with increasing Young’s modulus and Poisson’s ratio of the cement under dynamic-loading conditions. In addition, low mechanical cement strength would increase the risk of shear failure in the cement.
Haug, K.M. (Energy Resources Conservation Board/ Alberta Geological Survey) | Greene, P. (Energy Resources Conservation Board) | Schneider, C.L. (University of Alberta) | Mei, S. (Energy Resources Conservation Board/ Alberta Geological Survey)
Abstract: Although the majority of in situ oil sands schemes in Alberta do not encounter significant reservoir containment problems, there have been documented occurrences of fluid releases because of compromised caprock seals. The Energy Resources Conservation Board recognized the need for a greater understanding of the caprock and a project to characterize the geological and geomechanical factors was initiated. The objective of this project is to characterize the units above and below bitumen zones to determine which geological factors may affect the quality of the caprock seal. Mapping of the Cretaceous strata focuses on the spatial extent and thickness of the lower Clearwater shale unit overlying the McMurray Formation reservoir. Mapping of the underlying Devonian strata is targeted at better understanding the potential effects of salt dissolution and collapse of overlying strata on the integrity of the caprock seal. In addition, this project examined the stress regime above the in situ operations in the study area to evaluate the effects the operations would have on the stress regime quality of the caprock seal. Initial numerical model results demonstrated that stress reduction above an in situ operation may lead to the creation of vertical fractures if the fracture gradient is exceeded.
Gorecki, Charles David (Energy & Environmental Research Center) | Sorensen, James Alan (U. of North Dakota) | Klapperich, Ryan Joseph (Energy & Environmental Research Center) | Botnen, Lisa S. (Energy & Environmental Research Center) | Steadman, Edward N. (U. of North Dakota) | Harju, John A. (Gas Technology Institute (GTI))