A Sand-Arch Stability Constrained Dynamic Fractal Wormhole Growth Model for Simulating Cold Heavy-Oil Production with Sand

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3440-3456
Author(s):  
Haisheng Yu ◽  
Juliana Y. Leung
Keyword(s):  
Pressure Gradient ◽  
Growth Model ◽  
Heavy Oil ◽  
Stability Criterion ◽  
Flow Simulation ◽  
Oil Production ◽  
Sand Production ◽  
Heterogeneous Distribution ◽  
Fractal Pattern ◽  
Foamy Oil

Summary Cold heavy-oil production with sand (CHOPS) is a nonthermal primary process that is widely adopted in many weakly consolidated heavy-oil deposits around the world. However, only 5 to 15% of the initial oil in place is typically recovered. Several solvent-assisted schemes are proposed as follow-up strategies to increase the recovery factor in post-CHOPS operations. The development of complex, heterogeneous, high-permeability channels or wormholes during CHOPS renders the analysis and scalability of these processes challenging. One of the key issues is how to properly estimate the dynamic growth of wormholes during CHOPS. Existing growth models generally offer a simplified representation of the wormhole network, which, in many cases, is denoted as an extended wellbore. Despite it being commonly acknowledged that wormhole growth due to sand-arch failure is likely to follow fractal statistics, there are no established workflows to incorporate sand-arch stability constraints into the construction of these fractal wormhole patterns. A novel dynamic wormhole growth model is developed to generate a set of realistic fractal wormhole networks during the CHOPS operations. It offers an improvement to the diffusion limited aggregation (DLA) algorithm with a sand-arch stability criterion. The outcome is a fractal pattern that mimics a realistic wormhole growth path, with sand-arch failure and fluidization being controlled by sand-arch stability constraints. The fractal pattern is updated dynamically by coupling compositional flow simulation on a locally refined grid and a stability criterion for the sand arch: the wormhole would continue expanding following the fractal pattern, provided that the pressure gradient at the tip exceeds the limit corresponding to a sand-arch stability criterion. Important transport mechanisms including foamy oil (nonequilibrium exsolution of gas) and sand-arch failure are integrated. Public field data for several CHOPS fields in Canada are used to examine the results of the dynamic wormhole growth model and flow simulations. For example, the sand production history is used to estimate a practical range for the critical pressure gradient representative of the sand-arch stability criterion. The oil and sand production histories show good agreement with the modeling results. In many CHOPS or post-CHOPS modeling studies, constant wormhole intensity is commonly assigned uniformly throughout the entire domain; as a result, the ensuing models are unlikely to capture the complex heterogeneous distribution of wormholes encountered in realistic reservoir settings. This work, however, proposes a novel model to integrate a set of statistical fractal patterns. The entire workflow has been readily integrated with commercial reservoir simulators, enabling it to be incorporated in practical field-scale operations design.

Enhanced Oil Production Owing to Sand Flow in Conventional and Heavy-Oil Reservoirs

2001 ◽  
Vol 4 (05) ◽  
pp. 366-374 ◽  
Author(s):  
Yarlong Wang ◽  
Carl C. Chen
Keyword(s):  
Heavy Oil ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Absolute Permeability ◽  
Sand Production ◽  
Foamy Oil ◽  
Enhanced Production ◽  
Sand Control ◽  
Heavy Oil Reservoirs ◽  
Oil Flow

Summary A coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena in both heavy-oil reservoirs (northwestern Canada) and conventional oil reservoirs (i.e., North Sea). The model is developed and implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. Both the enhanced production and the ranges of the enhanced zone are calculated, and the effects of solid production on oil recovery are analyzed. Field data for solid production and enhanced oil production, collected from about 40 wells in the Frog Lake area (Lloydminster, Canada), are used to validate the model for the cumulative sand and oil production. Our studies indicate that the enhanced oil production is mainly contributed (1) by the reservoir porosity and permeability improvement after a large amount of sand is produced, (2) by higher mobility of the fluid caused by the movement of the sand particles, and (3) by foamy oil flow. A relative permeability reduction after a certain period of production may result in a pressure-gradient increase, which can promote further sand flow. This process can further improve the absolute permeability and the overall sand/fluid slurry production. Our numerical results simulate the fact that sand production can reach up to 40% of total fluid production at the early production period and decline to a minimum level after the peak, generating a high-mobility zone with a negative skin near the wellbore. Such an improvement reduces the near-well pressure gradient so that the sanding potential is weakened, and it permits an easier path for the viscous oil to flow into the well. Our studies also suggest that the residual formation cement is a key factor for controlling the cumulative sand production, a crucial factor that determines the success of a cold production operation and improved well completion. Introduction Field results from many heavy-oil reservoirs in northwestern Canada, such as Lindbergh and Frog Lake in the Lloydminster fields, suggest that primary recovery is governed mainly by the processes of sand production and foamy-oil flow.1–3 To manage production in such reservoirs, the challenge we face is optimizing production so that sand production is under control. For decades, industries have developed various highly effective tools for sand control. In practice, however, sand control often results in reduced oil flow or no production at all, particularly in heavy-oil reservoirs. For example, it has been observed that an average oil production of only 0.0 to 1.5 m3/d can be achieved in a well in which no sand production is allowed, while 7 to 15 m3/d oil may be produced with sand production.4 A significant improvement in production also has been reported by allowing a certain amount of sand produced before gravel packing in the high-rate production well in conventional reservoirs.5 It seems that sanding corresponds to a high oil production in these reservoirs, as sand production either increases the reservoir mobility or allows the development of highly permeable zones such as channels (wormholes).1 Encouraging sand production to enhance oil production, on the other hand, increases oil production costs owing to environmental problems. Consequently, neither trying to eliminate the sand production completely nor letting sand be produced freely, we attempt to develop a quantified model linking sand rate and reservoir enhancement so that we can forecast the economic outcome of such an operation. The investigation of sand production has been extensive, but it has been limited primarily to the areas of incipience of sand production and control. Sand arching and production initiation from a cavity simulating a perforating tunnel were studied, and a critical flow rate before sanding was found for single-phase steady-state flow.6 Such a study was extended to gas reservoirs, in which the gas density is a function of pressure,7 and to those formations subject to nonhydrostatic loading.8,9 Studying the enhanced production and the cumulative sand production, a series of simplified models for massive sand production have been developed.10,11 Similar models based on a coupled classic geomechanics model were also proposed thereafter.12,13 Because these aforementioned sand-production models are somewhat restricted by the fact that they are simplified by analytical methods, and in reality reservoir formations are much more complex (i.e. nonlinear behaviors), a numerical model coupling a multiphase transient fluid flow to elastoplastic geomechanical deformation is thus developed in this article; its purpose is to simulate these major nonlinear effects. According to the proposed model, a corresponding plastic yielding zone (or a disturbed zone) propagates into reservoir formation because of the transient fluid pressure diffusion, and the corresponding effective stresses change near a wellbore. A possible absolute permeability change inside the yielding zone is also considered, as dilatant deformation developed may enhance the permeability in the plastic zone. As a primary unknown, saturation is assumed to change with the induced pore-pressure change. The relative permeability is updated by the saturation, which in turn changes the response of the pore pressure and the skeleton deformation. A continuum mechanics approach is used in our calculation. Rather than characterizing each random wormhole proposed,1,4,5 we impose a homogeneous medium with an average permeability to make the numerical solutions manageable. The wormholes or geomechanical dilatation zone can be represented by a higher-permeability region in the plastic yielding zone owing to porosity enhancement,1 and solid flow is considered as a continuous moving phase along the transient fluid flow. Alternatively, a sand erosion model was introduced, and the geomechanics coupling to a single-phase flow was presented previously.14,15

Quantification of Sand Production Using a Pressure-Gradient-Based Sand-Failure Criterion

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 988-1001 ◽  
Author(s):  
Zhaoqi Fan ◽  
Daoyong Yang ◽  
Xiaoli Li
Keyword(s):  
Pressure Gradient ◽  
Heavy Oil ◽  
Failure Criterion ◽  
Oil Sands ◽  
Pore Scale ◽  
Sand Production ◽  
Foamy Oil ◽  
Recovery Processes ◽  
Oil Flow ◽  
Gradient Based

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 sand-failure criterion can be used to characterize the sand production in a CHOPS process.

Well/Wormhole Model of Cold Heavy-Oil Production With Sand

SPE Journal ◽  
2013 ◽  
Vol 19 (02) ◽  
pp. 260-269 ◽  
Author(s):  
C.M.. M. Istchenko ◽  
I.D.. D. Gates
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Field Experiments ◽  
Oil Production ◽  
Sand Production ◽  
Foamy Oil ◽  
Fluidization Velocity ◽  
Growth Criterion ◽  
Foamy Oil Flow ◽  
Oil Flow

Summary Cold heavy-oil production with sand (CHOPS) is a nonthermal heavy-oil-recovery technique used primarily in the heavy-oil belt in eastern Alberta, Canada, and western Saskatchewan, Canada. Under CHOPS, typical recovery 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 process becomes uneconomic, making CHOPS wells and fields prime candidates for enhanced-oil-recovery (EOR) follow-up process field optimization. CHOPS wells show an enhancement in production rates compared with conventional primary production, which is explained by the formation of high-permeability channels known as wormholes. The formation of wormholes has been shown to exist in laboratory experiments as well as field experiments conducted with fluorescein dyes. The major mechanisms for CHOPS production are foamy oil flow, sand failure (or fluidization), and sand production. Foamy oil flow aids in mobilizing sand and reservoir fluids, leading to the formation of wormholes. Foamy oil behavior cannot be effectively modeled by conventional pressure/volume/temperature (PVT) behavior. Here, a new well/wormhole model for CHOPS is proposed. The well/wormhole model uses a kinetic model to deal with foamy oil behavior, and sand is mobilized because of sand failure determined by a minimum fluidization velocity. The individual wormholes are modeled in a simulator as an extension of a production well. The model grows the well/wormhole dynamically within the reservoir according to a growth criterion set by the fluidization velocity of sand along the existing well/wormhole. If the growth criterion is satisfied, the wormhole extends in the appropriate direction; otherwise, production continues from the existing well/wormhole until the criterion is met. The proposed model incorporates sand production and reproduces the general production behavior of a typical CHOPS well.

Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production

2021 ◽  
Author(s):  
Jasmine Shivani Medina ◽  
Iomi Dhanielle Medina ◽  
Gao Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Elevated Temperatures ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Gas Recovery ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Pressure Depletion

Abstract The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term "foamy oil," by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally. This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR). The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature. A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range. With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.

Research Progress in the Mathematical Models on Mechanism of Cold Heavy Oil Production with Sand

2012 ◽  
Vol 524-527 ◽  
pp. 1866-1871
Author(s):  
Rong Rong Wang ◽  
Jian Hou ◽  
Xian Song Zhang ◽  
Xiao Dong Kang
Keyword(s):  
Mathematical Models ◽  
Heavy Oil ◽  
Oil Production ◽  
Research Progress ◽  
Sand Production ◽  
Experiment Research ◽  
Permeability Enhancement ◽  
Field Practice ◽  
Oil Flow ◽  
Research Show

Cold Heavy Oil Production with Sand (CHOPS) is an emerging technology. Field practice and laboratory experiment research show the main mechanism of CHOPS are stable foam oil flow producing the internal driving force and the mass sand inflow forming wormhole network leading to the permeability enhancement. In this paper, we summarize the mathematical models describing the mechanism of CHOPS: foam oil model, wormhole model and comprehensive model. The foam oil models mainly describe the formation, properties and flow of foam oil while the wormhole models describe the wormhole growth, the flow in wormhole and sand production predicting. Finally, we discuss the emphasis and directions of research in the future.

CT Imaging of Wormhole Growth Under Solution-Gas Drive

1999 ◽  
Vol 2 (01) ◽  
pp. 37-45 ◽  
Author(s):  
Bernard Tremblay ◽  
George Sedgwick ◽  
Don Vu
Keyword(s):  
Pressure Gradient ◽  
Production Process ◽  
Heavy Oil ◽  
Sand Production ◽  
High Permeability ◽  
Drive Mechanism ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas ◽  
Live Oil

Summary The cold production process has increased primary heavy oil production and has been applied with commercial success in the Lloydminster area (Alberta, Canada). In this process, the production of sand is encouraged in order to form high permeability channels (wormholes) within the formation. The process depends on the formation and flow of foamy oil into the wormholes as these grow away from the wellbore and into the reservoir. The formation and growth of a wormhole was visualized using a computed tomography scanner, in an experiment in which oil flowed through a horizontal sandpack and out an orifice. The only drive mechanism was the formation and expansion of methane bubbles within the live oil. The pressure gradient at the tip of the wormhole was approximately 1 MPa/m when it started to develop at the orifice. Two conditions appear necessary for wormholes to keep growing:the pressure gradient at the tip of the wormhole must be sufficiently large to dislodge the sand grains,the pressure gradient along the wormhole must be large enough to transport the sand from the tip to the orifice. The pressure gradient at the tip of the wormhole was 2.9 MPa/m when it reached its maximum length. This suggests that, although the pressure gradient at the tip was sufficient for erosion to occur, the sand could not be carried along the wormhole causing the wormhole to stop growing. The pressure depletion experiment suggests that wormholes can easily develop in uncemented sand in the field since the maximum oil production rate during wormhole growth (18 cm3/day) was significantly lower than in the field. The minimum pressure gradient (11 kPa/m) necessary for sand transport along the wormhole is important in calculating the extent of wormhole growth in the field. Introduction Cold production is a nonthermal recovery process used in uncemented heavy oil reservoirs in which sand and oil are produced together. Production rates from wells on cold production can be up to 30 times larger than the rate predicted by Darcy flow without sand production. In order to better understand the role of sand production in the cold production process, tracer injection tests were performed by well operators.1,2 Tracer dye velocities of 7 m/min were measured between certain wells. The dye showed up 18 h later at 2 km away from the injection well.1,2 The rapid flow of the tracer suggested that it flowed through a small channel excluding the possibility of a fracture or cavity around the well. We confirmed directly the development of high conductivity channels "wormholes" in the laboratory in two previous experiments.3,4 An orifice was located at the end of a sandpack and heavy oil was injected into the sandpack at constant flow rates. The heavy oil did not contain any dissolved gas. A high permeability channel (wormhole) was observed to develop at a critical flow rate. The drive mechanism in these experiments was external since a constant flow rate was maintained using a positive displacement pump. The drive mechanism for the cold production process is solution-gas drive.5 We wanted to determine whether or not a wormhole would develop under solution-gas drive. The pressure vessel used in the two previous external drive experiments was modified to handle the live oil. This required maintaining a back pressure at the orifice end of the sandpack. This back pressure was reduced at a constant rate of 205 kPa/day during the experiment. We observed that a wormhole developed in the sandpack even though the only drive mechanism was the expansion of gas bubbles in the heavy oil. The critical pressure gradient required for the wormhole to start growing (1 MPa/m) was significantly lower than in the two previous dead oil experiments: 800 MPa/m in a first experiment3 and 32 MPa/m in a second experiment.4 This significant difference in the critical pressure gradient is attributed to a destabilization of the sand grains at the wormhole tip due to the growth of the gas bubbles in the pressure depletion experiment. The wormhole stopped growing when the pressure gradient along the wormhole was equal to 11 kPa/m. These measurements are required in order to estimate how far these wormholes can extend in the field. This experiment shows that a wormhole can develop in a sandpack by solution gas drive. Materials The Clearwater sand used in preparing the pack was obtained from collection tanks at Suncor's former cold production pilot field in Burnt Lake, Alberta, Canada. The sand was packed in 2 cm layers with a hydraulic press under 27.6 MPa. The high packing stress was necessary to obtain a porosity of 34% representing field conditions (32-34%) and to give the sand a cohesive strength comparable to field values by creating more interlocking between sand grains. The porosity of naturally deposited sand ranges from 37% for a well-sorted, well-rounded, medium to coarse sand, to more than 50% for poorly sorted, fine-grained sands with irregular shaped grains.6 Either compaction or cementation is required to reduce the porosity of naturally deposited sands to field values. Porosity reduction by compaction of sand sediments can occur by plastic flow, crushing, fracturing, or pressure solution at grain contacts.7 An average particle size distribution of the sand after packing at 27.6 MPa is shown in Fig. 1. The average size of the sand grains was 198 microns. The fines content (less than 37 microns) was 8.4% by weight. The permeability of the sand pack was 1.7 Darcy. The pore volume of the sandpack was 2336 cm3.

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