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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 proposed sand-failure criterion was initially developed at the pore-scale level, while a pseudointeraction force between two neighboring sand grains was proposed to implicitly represent the potential contributions of cementation and geomechanical stresses to the fluidization of sand. 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. With the bottomhole pressure being an input constraint, the proposed sand-failure criterion was validated with good agreement by reproducing production profiles and wormhole propagation from laboratory experiments and a CHOPS well in the Cold Lake Oil Sands Area. 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 typical characteristics of production profiles for CHOPS wells were mainly summarized from field experiences. 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).
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. In the first phase, we measure baselines for water and kerosene imbibition into the rock samples by conducting spontaneous imbibition tests. In the second phase, we measure expansion of the rock samples during imbibition of water and kerosene, in separate tests, using a linear variable differential transformer (LVDT). In the third phase, we measure imbibition-induced tensile stress during water imbibition into the samples.
The results show that both HRB and DUV shale samples imbibe more water than kerosene, due to water adsorption by clay minerals. Imbibition of water increases the porosity of the HRB and the DUV samples by up to 0.94 and 0.25 percentage points, respectively. Expansion of all samples is anisotropic, with higher expansion perpendicular to the depositional lamination. Water imbibition into the samples induces an expansive stress as high as 17 psi. Moreover, applying confining stress reduces the imbibition of water by up to 18.1% and 33.7% in the HRB and DUV samples, respectively.
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.
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))
Copyright 2012, Carbon Management Technology Conference This paper was prepared for presentation at the Carbon Management Technology Conference held in Orlando, Florida, USA, 7-9 February 2012. This paper was selected for presentation by a CMTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed and are subject to correction by the author(s). The material does not necessarily reflect any position of the Carbon Management Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Carbon Management Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of CMTC copyright. Abstract The Plains CO 2 Reduction (PCOR) Partnership and Spectra Energy Transmission (SET) are investigating the feasibility of a carbon capture and storage (CCS) project near Fort Nelson, British Columbia, Canada. The project aims to reduce carbon dioxide (CO 2) emissions from SET's Fort Nelson sour gas-processing plant by injecting up to 2 million tonnes of sour CO 2 (approximately 95% CO 2, 4% hydrogen sulfide [H 2 S], and 1% methane [CH 4 ]) a year into a deep mid-Devonian-age carbonate reef for long-term geologic storage. The Fort Nelson CCS project provides a unique opportunity to develop a set of cost-effective, risk-based monitoring techniques for large-scale storage of sour CO 2 in deep saline formations. An approach is being developed that integrates characterization, modeling, risk assessment, and monitoring into an iterative process to produce superior quality results during each phase of the project. During the preinjection phase of the project, the characterization activities are used as input to the modeling effort.
The Horn River Basin of northeastern British Columbia, Canada, contains natural gas in three Devonian shale units. Isopachs, depths, and net-to gross-pay ratios were determined from well logs for the Muskwa, Otter Park, and Evie Shales and then gridded. Pressure gradients were determined from well test and production data and then gridded into a single grid shared between shales. Because grid points were shared between each grid, volumetric and adsorbed gas equations could be integrated into each grid point. Static values or distributions could then be applied to equation variables and Monte Carlo simulations run to determine probabilistic gas in place (GIP) and marketable resources for each grid point, which were then summed for each shale.
Grid points for the isopach and depth maps were treated as static values in the equations while net-togross and pressure gradient grid points became most likely values in Beta distributions where end points were assigned using regional low and high values. Most non-mapped variables in the equations were filled with Beta distributions based on typical values in the area and then applied across the basin without any local variations. On each distribution, whether based on mapped or unmapped variables, a second, overlying distribution was applied on a basin scale. This made entire iterations run a full range from pessimistic to optimistic. A few non-mapped variables in the equations were given static values.
Recoverable gas resources were estimated by applying a recovery factor to free GIP estimates. Recoverable volumes from adsorbed GIP estimates were determined from a recovery factor applied to the portion of gas that would desorb during production as pressure decreased to the assumed well abandonment pressure. To determine marketable gas, gas impurities and fuel gas that would be used for processing and transport were estimated and subtracted from the recoverable estimates. Further, certain lower quality areas of the basin were excluded from the assessment, based on a low likelihood of being
Horn River Group (HRG) shales are prime exploration targets. The shales form a 200m thick package of over-pressured, organic rich, siliceous mudrocks found at drilling depths between 2400-2700m. The gross thickness of the shale interval and the observed frac barriers within the shale package present a challenge for maximizing the stimulated rock volume when completing wells. Within Devon Canada, an exploration program was designed to evaluate reservoir complexity and heterogeneity, the ultimate goal being to optimize horizontal, vertical and lateral well placement while balancing recovery factor and capital costs.
Core and log data from vertical wells were analyzed to target optimal horizontal drilling zones for hydraulic fracture initiation and ease of drilling. Geomechanical log analysis supports the observation made from microseismic data that frac height growth through the frac barriers in the shale package happens preferentially depending upon the direction from which the fracture was initiated.
Project Location & Description
The Horn River Basin is located approximately 634 miles northwest of Calgary in the north eastern corner of British Columbia. Devon has acquired over 234 sections on three blocks of land (Komie, McAdam, and Petitot).
Devon has drilled 11 horizontal and 9 vertical wellbores to delineate the resource. Production from horizontal wellbores has been focused on the Komie block which will be the subject of this paper. (See Figure 1)
An uninterrupted economical supply of frac water is critical to the successful development of the Horn River Devonian shales. and Apache have progressed our water supply from tank truck delivery of fresh surface waters to an integrated, subsurface saline water treating and distribution system. The current system is designed to deliver water at a rate of 16 m3/min to a maximum daily volume of 16,000 m3 or enough water for 3-4 fracs per day. This presentation will discuss our experiences with fresh surface waters, the design and implementation of the pilot plant and the design, construction and operation of the full scale sour water processing plant. Another aspect that will be discussed are the water source wells including geology, drilling, completion and high volume lift systems.
The Horn River shale gas play has been estimated to hold more than 500 Tcf by the Canadian Society of Unconventional Gas; being the third largest natural gas accumulation discovered to date in North America. It is the first shale gas play of its type in Canada and similar, in many aspects, to the Barnett Shale in the Fort Worth Basin near Dallas, Texas. To enable the recovery of this resource, multiple large slickwater fracture stimulations have been applied to horizontal wells. The source of this water is the Debolt Formation, a regional sour aquifer, which can supply water at the rates required to support development. However many innovations in water treatment are required to enable the water to be suitable for use in shale gas completions. This paper discusses the process of progression from identifying the need for a subsurface completions water source to treatment of sour Debolt water for use in fracture stimulation operations
Rivero, Jose A. (Schlumberger) | Coskuner, Gokhan (Husky Energy) | Asghari, Koorosh (U. of Regina) | Law, David Hin-Sum (Schlumberger) | Pearce, Andrew (Schlumberger) | Newman, Robert (Schlumberger) | Birchwood, Richard Anthony (Schlumberger) | Zhao, John (Schlumberger) | Ingham, Jonathan Paul (Schlumberger)
Cold Heavy Oil Production with Sand (CHOPS) has been widely and successfully applied for the last three decades in the Heavy Oil Belt region that straddles the provinces of Alberta and Saskatchewan in Canada. As its name suggests, the method relies on continuous production of sand to improve the recovery of oil from the reservoir. In CHOPS, a significant pressure drawdown around the wellbore is created by using progressive cavity pumps, which causes the loosely consolidated formation to fail, creating increased permeability channels, usually called wormholes, through which, a slurry-like mixture of sand, oil and water flows.
Many attempts have been made to use conventional numerical reservoir simulators to model the CHOPS process. However, many of the commercial finite-difference reservoir simulators do not incorporate capabilities to model the complex geomechanical processes responsible for the failure of poorly consolidated formations in CHOPS. To circumvent these limitations, several approaches have been proposed. The most common relies on explicitly defining high permeability channels that radiate from the producing wells in an attempt to mimic wormholes created during CHOPS production.
In this paper, we present a different, more rigorous approach that relies on the coupling of a finite-element geomechanical simulator with a finite-difference reservoir simulator. In the coupling process, the geomechanical simulator uses the pressure gradients calculated by the reservoir simulator to determine changes in the stress regime of the reservoir. In the case of CHOPS, these changes cause failure in the loosely consolidated formation, which in turn induces sand production with a corresponding increase in porosity and permeability. The new porosity and permeability values in the affected gridblocks are then fed back to the reservoir simulator, which is now capable of incorporating the effects of formation failure into fluid flow calculations. This process is then repeated at user-controlled intervals during the course of the simulation. The methodology has been validated by successfully history matching the production data from a section of a heavy oil field operated by Husky Energy in Western Canada. In this paper we compile the data integration efforts to create a coupled geomechanical model and the results of the history match.
Heavy oil producers in Canada have adopted the primary production strategy of encouraging sand production in a process commonly know as Cold Heavy Oil Production with Sand (CHOPS). While this technique yields economic oil rates, the production of sand introduces many other operating costs and prevents the implementation of technologies, such as gathering lines, that are not compatible with massive sand production. A new concept has been proposed that takes advantage of the reservoir processes of CHOPS but removes most of the extra operating costs and barriers to technology associated with sand production. This paper discusses the new process, how it could benefit heavy oil production operations and the technical challenges that need to be addressed before this concept can be implemented.