Cold Heavy Oil Production With Sand Research Articles

Quantification of Methane Emissions from Cold Heavy Oil Production with Sand Extraction in Alberta and Saskatchewan, Canada.

Cold heavy oil production with sand (CHOPS) is an extraction process for heavy oil in Canada, with the potential to lead to higher CH4 venting than conventional oil sites, that have not been adequately characterized. In order to quantify CH4 emissions from CHOPS activities, a focused aerial measurement campaign was conducted in the Canadian provinces of Alberta and Saskatchewan in June 2018. Total CH4 emissions from each of 10 clusters of CHOPS wells (containing 22-167 well sites per cluster) were derived using a mass balance computation algorithm that uses in situ wind data measurement on board aircraft. Results show that there is no statistically significant difference in CH4 emissions from CHOPS wells between the two provinces. Cluster-aggregated emission factors (EF) were determined using correspondingly aggregated production volumes. The average CH4 EF was 70.4 ± 36.9 kg/m3 produced oil for the Alberta wells and 55.1 ± 13.7 kg/m3 produced oil for the Saskatchewan wells. Using these EF and heavy oil production volumes reported to provincial regulators, the annual CH4 emissions from CHOPS were estimated to be 121% larger than CHOPS emissions extracted from Canada's National Inventory Report (NIR) for Saskatchewan. The EF were found to be positively correlated with the percentage of nonpiped production volumes in each cluster, indicating higher emissions for nonpiped wells while suggesting an avenue for methane emission reductions. A comparison with recent measurements indicates relatively limited effectiveness of regulations for Saskatchewan compared to those in Alberta. The results of this study indicate the substantial contribution of CHOPS operations to the underreporting observed in the NIR and provide measurement-based EF that can be used to develop improved emissions inventories for this sector and mitigate CH4 emissions from CHOPS operations.

Saskatchewan’s oil and gas methane: how have underestimated emissions in Canada impacted progress toward 2025 climate goals?

Canada has set ambitious methane emission reduction targets for its oil and gas industry, and recently, the province of Saskatchewan—Canada’s second largest oil producing region—announced it has already exceeded the first of these targets. Using detailed operator-reported emissions data, published for the first time from Saskatchewan in 2022, we estimate the province’s upstream oil and gas methane inventory to independently evaluate the reported emission reductions. While the inventory suggests that Saskatchewan has surpassed its target, the inclusion of recently published site-level aerial measurement data from cold heavy oil production with sand (CHOPS) wells suggests that the methane inventory is underestimated by between 30% and 40%. This inventory update is supported by new regional aerial measurements confirming the continued underestimation of emissions at CHOPS wells. Since these emissions likely evade required reduction under current regulations, we evaluate achievable emission levels if such CHOPS emissions are accurately measured/reported. The results show Saskatchewan can achieve much deeper emission reductions under current regulations with improved emission measurement, reporting, and verification methods. We discuss the benefits and risks inherent in Saskatchewan’s regulatory approach where emission limits are primarily set at the operator-level.

Methane Venting at Cold Heavy Oil Production with Sand (CHOPS) Facilities Is Significantly Underreported and Led by High-Emitting Wells with Low or Negative Value.

Cold Heavy Oil Production with or without Sand, CHOP(S), facilities produce a significant portion of Canada's conventional oil. Methane venting from single-well CHOPS facilities in Saskatchewan, Canada was measured (i) using Bridger Photonics' airborne Gas Mapping LiDAR (GML) at 962 sites and (ii) on-site using an optical mass flux meter (VentX), ultrasonic flow meter, and QOGI camera at 11 sites. The strong correlation between ground measurements and airborne GML supported subsequent detailed analysis of the aerial data and to our knowledge is the first study to directly test the ability of airplane surveys to accurately reproduce mean emission rates of unsteady sources. Actual methane venting was found to be nearly four times greater than the industry-reported levels used in emission inventories, with ∼80% of all emissions attributed to casing gas venting. Further analysis of site-total emissions revealed potential gaps in regulations, with 14% of sites appearing to exceed regulated limits while accounting for 61% of measured methane emissions. Finally, the concept of marginal wells was adapted to consider the inferred cost of methane emissions under current carbon pricing. Results suggest that almost a third of all methane is emitted from environmentally marginal wells, where the inferred methane cost negates the value of the oil produced. Overall, the present results illustrate the importance of independent monitoring, reporting, and verification (MRV) to ensure accuracy in reporting and regulatory compliance, and to ensure mitigation targets are not foiled by a collection of disproportionately high-emitting sites.

Integrated characterization of wormhole growth and propagation dynamics in CHOPS reservoirs with a unified and consistent ensemble-based framework

In this paper, a unified and consistent ensemble-based framework has been established for the first time to simulate the wormhole growth and propagation dynamics in a cold heavy oil production with sand (CHOPS) reservoir. More specifically, a recently modified pressure-gradient-based (PGB) sand failure criterion has been integrated into a reservoir simulator via a damped-iterative-ensemble-Kalman-filter (damped-IEnKF) framework in which foamy oil mechanisms are considered to quantify the changes in porosity and permeability in a CHOPS reservoir conditioned to its oil, water, gas, and sand production profiles. Subsequently, such an integrated model was applied to a single-well case from the Cold Lake heavy oil deposit and then a five-well case from the Lloydminster heavy oil area by alternatively combining the skin factor concept to reduce the computational expenses without compromising the simulation accuracy. The composite impact of sand failure and slurry flow on the multiphase flow behaviour was examined with different sets of relative permeability curves at each distinct production stage. By conditioning the simulated model to the observed production in the five-well case, skin factors have been alternatively assigned to each well to quantify the near wellbore damage on the initiation and development of wormhole networks. Not only have the production profiles been well matched, but also satisfactory agreements between the simulation outcomes and the in-situ observations have been obtained for both cases. It is found that the saturations of residual oil and connate water can be both significantly reduced by the sand failure mechanism, while the overall relative permeability can be reduced by the presence of slurry flow. A high pressure difference in the vicinity of a wellbore was formed owing to a large skin factor with respect to the restricted wellbore flow rate, significantly aggravating the sand failure. To better reproduce the production profiles in the five-well case, different skin factors were used for each well. In practice, the wormhole growth and propagation dynamics can be accurately and efficiently evaluated and forecasted with such an integrated model in a CHOPS reservoir, demonstrating its practicality and reliability in simulating the wormhole network dynamics and evaluating the performance of subsequent enhanced oil recovery (EOR) processes within a unified, efficient, and consistent framework.

Mathematical modeling of foamy-oil flow in a cyclic solvent injection process

Foamy-oil flow is one of the main mechanisms for cold heavy oil production with sand (CHOPS) and cyclic solvent injection (CSI) processes. The flow pattern of foamy oil was observed in previous experimental studies under reasonable reservoir conditions. This study aims to investigate the foamy-oil flow mechanisms through theoretical modeling. A mathematical model is developed, which couples a solvent concentration field and a pressure field through flow velocity and oil viscosity, in which a pseudo-chemical reaction is used to describe the release of gas. The model is numerically solved by the Newton−Raphson iterative method. Results show that, firstly, during the pressure drawdown process, propane concentration decreases and oil viscosity increases with solvent exsolution in the transition zone, which restricts the bubbles coalescence and conduces to the formation of foamy oil. Secondly, the existence of bubbles leads to the buildup of local pressure gradient and causes the spatial difference of flow velocity. Moreover, when the threshold velocity is reached, the bubbles coalesce rapidly to form free gas, pushing the oil in the foamy region forward to the gas zone. Finally, the total waves of foamy-oil flow are generally 2 to 4, depending on the initial solvent concentration, oil viscosity, and pressure depletion rate. Higher initial solvent concentration, faster pressure depletion, and lighter original heavy oil lead to the easier induction of foamy-oil flow.

Characterization of Wormhole Growth and Propagation Dynamics During Cold Heavy Oil Production with Sand (CHOPS) Processes by Integrating Rate Transient Analysis and a Pressure-Gradient-Based Sand Failure Criterion

Summary In this work, theoretical models have been formulated, validated, and applied to characterize the dynamic wormhole growth and propagation dynamics during cold heavy oil production with sand (CHOPS) processes by integrating rate transient analysis (RTA) and a pressure-gradient-based (PGB) sand failure criterion. More specifically, a coupling fluid-solid flow model is proposed by incorporating the recently proposed PGB sand failure criterion with sand production. Then, the source function method is applied to solve the fluid flow problem in the matrix subsystem by considering each generated wormhole segment as a sink source, while the finite difference method is applied to solve the fluid-sand flow problem in the wormhole subsystem. The sand failing at each segment is induced and propagated once the PGB sand failure criterion has been reached. Furthermore, transient-rate-type curves are generated to determine the dynamic wormhole network conditioned to the measured fluids and sand production profiles. Also, effects of the PGB sand failure criterion and reservoir properties on the transient rate behavior for CHOPS wells can be examined and analyzed. A gradual increase in the production rate profile occurs at the early times due to the wormhole growth and propagation. The wormhole network can be dynamically characterized by matching both the sand production rate and transient fluid production rate. The former is found to be greatly affected by the breakdown pressure gradient, while the effective wormhole coverage and intensity dominate the latter. Once the transient rate responses for both static and dynamic wormhole networks are validated with numerical simulation, the newly proposed method has been extended to field applications under various constraints, demonstrating that the fluid and sand production data of CHOPS wells can be integrated to accurately characterize the dynamic wormhole network within a unified, consistent, and efficient framework.

Integrated characterization of wormhole network by use of a modified pressure-gradient-based (PGB) sand failure criterion and ensemble-based history matching during CHOPS processes

In this paper, a damped iterative ensemble Kalman filter (IEnKF) technique has been developed and integrated with a recently modified pressure-gradient-based (PGB) sand failure criterion to implicitly and inversely characterize the dynamic wormhole network during cold heavy oil production with sand (CHOPS) processes. With an improved upscaling process, not only has a microscopic PGB sand failure criterion been properly upscaled to the grid-scale simulation, but also it can be dynamically, implicitly, and inversely determined. Then, such a sand failure model together with three-phase relative permeability is validated and applied to reproduce wormhole network in a laboratory experiment conditioned to its sand production profile. Good agreements between the observed and simulated cumulative production profiles including oil, gas, and sand have been achieved with satisfactory convergence by integrating the ensemble-based history matching method. The simulated wormhole network has shown its great similarity to the experimental observations, while the convergence of the ensemble-based history matching algorithm is greatly improved with a widespread of initial ensembles in each grid. Furthermore, deviations between the observed and updated production profiles can be significantly minimized by dividing the entire production period into three sequential stages, each of which has its distinct relative permeability curves due to the major effect (i.e., foamy oil flow, sand failure, and slurry flow) on its multiphase flow behaviours, respectively. By integrating the ensemble-based sand failure model with the damped-IEnKF method, the dynamic wormhole network during a CHOPS process can be accurately characterized with satisfactory convergence, demonstrating its robustness and practicality of dynamically and inversely simulating the preferential wormhole network. Such an ensemble-based sand failure model can be seamlessly incorporated with any commercial reservoir simulators under various conditions. • A hybrid IEnKF-PGB technique is developed to characterize wormhole network for CHOPS wells. • Good agreements between the observed and simulated cumulative production profiles are achieved. • Simulated wormhole network shows its great similarity to the experimental observations. • Dividing the production period into three stages minimizes deviations between observed and updated production profiles. • This hybrid technique is robust and can be seamlessly coupled with any reservoir simulators.

Geomechanical modelling of cold heavy oil production with sand

Abstract The contribution of geomechanics to provide a rigorous quantification of porosity changes and associated permeability changes is often neglected when considering hydrocarbon production. However, it often has significant effects on production rates and ultimate recovery. For the cold heavy oil production with sand (CHOPS) technique, geomechanics is the key for reservoir simulations and promoting successful operations. In fact, the technique employed in CHOPS significantly affects the stress state within the reservoir by inducing “on-purpose” formation damage. It is not only vital to comprehend the behaviour of the reservoir during production, but it is crucial to identify how to harness that behaviour to improve productivity. In order to simulate the mechanical behaviour of unconsolidated sand material, an elastoplastic damage model was formulated. Fluid-flow-geomechanical modelling was then performed for predicting individual well behaviour and overall field performance. The combined effect of fluid-flow and geomechanics improved predictions with respect to oil, water, and gas production rates at key wells. Fluid rates matched satisfactorily most of the wells. In addition, the onset and propagation of equivalent wormhole networks were quantified throughout the production history. This enabled quantification of the volume of produced sand at individual wells. The comparisons between the measured and simulated sand volume rate at well locations showed reasonable agreement. Such calibrated models can then be used for the placement of new wells to optimize production.

Progressing-Cavity-Pump Configuration Addresses Operational Challenges

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201130, “Novel Progressing-Cavity-Pump Configurations Address Operational Challenges,” by Lonnie Dunn, SPE, Ryan Rowan, and Abhishek Prakash, Lifting Solution, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition-Americas, 10-12 November. The paper has not been peer reviewed. While downhole progressing-cavity-pump (PCP) designs provide options for end users, the numerous products available, combined with a lack of industry standardization, can make selection and application challenging. The complete paper provides an overview of the development of a PCP concept and implementation, which is not included in this synopsis, and then summarizes two novel PCP configurations deployed to address specific operational challenges. Design and Manufacturing, Configuration 1 A novel PCP configuration was developed from phased design trials and experience in cold heavy-oil production with sand (CHOPS) wells. This configuration uses a modified rotor to create alternating sections of contact and noncontact within a conventional stator (Fig. 1). The rotor is landed in the stator and operated until there is a performance decline. Then, the rotor is repositioned to move the active section of the rotor into the areas of the stator where there originally was no contact and, as such, normally no associated damage. Keeping the length of the alternating sections short simplifies the surface rotor positioning process, allowing it to be performed riglessly. The main benefit of this is that, rather than having to pull the rod string and run a different rotor, the same rotor is used and repositioned through lifting of the rod string at surface.

Experimental Study on Mechanism of Foamy Oil-Assisted Methane Foam Flooding in an Etched Glass Micromodel

A number of heavy oil reservoirs under cold heavy oil production with sand (CHOPS) show anomalously good primary performance due to foamy oil flow. However, as the pressure of the reservoir depletes, the foamy oil phenomenon gradually disappears and the development gradually deteriorates. In this paper, a new method named methane foam flooding is proposed as an effective enhanced heavy oil recovery process. In this paper, we take advantage of Ross miles foam equipments to select foaming agents and evaluate the foam ability, study and analyze the foam ability of different foam agent in different concentrations. and through visual microscopic model experiments to study the oil displacement mechanism and flow characteristics of methane foam flooding. The results show that foaming agent ZY-1 has excellent foam comprehensive properties, and it has the best foam stability at 1% concentration. It can be found from the micromodel flood experiments that methane foam flooding can effectively block the formation of high permeability channels, delaying the production of methane gas, emulsifying crude oil and changing the wettability of the rock to enlarge a sweeping volume and improve oil displacement efficiency.

A modified pressure-gradient-based (PGB) sand failure criterion for dynamically and preferentially characterizing wormhole growth and propagation during CHOPS processes

In this paper, a recently developed pressure-gradient-based (PGB) sand failure criterion has been modified to improve its applicability for accurately quantifying the dynamic and preferential wormhole growth and propagation during cold heavy oil production with sand (CHOPS) processes. More specifically, the resistance of sand mobilization is analyzed and mechanical balance at pore-scale is established. The heterogeneous porosity distribution is newly integrated into the PGB sand failure criterion to identify the preferential directions of wormhole propagation. The sand failure is quantitatively examined by comparing the pressure gradients along with the potential directions at a threshold pressure gradient. Such an improved PGB sand failure criterion has been incorporated with a commercial reservoir simulator, in which three sets of relative permeability are utilized to represent the three physically distinct stages of the CHOPS processes. Subsequently, the newly modified PGB sand failure criterion is validated by laboratory sand production experiments and then extended to a field application. Good agreements between the simulated and measured data (i.e., production profiles and pressure) have been achieved from the laboratory experiments. As the preferential directions of the wormhole propagation can be dynamically determined through pressure gradient and porosity distribution, the simulated wormholes are much closer to the experimental observations than the previous work (Fan et al., 2019). The accuracy of the simulated production profiles has also been significantly improved by using three sets of permeability to separately represent the dominant impacts (i.e., sand failure, slurry flow, and boundary effect) on different stages of the CHOPS processes. In addition, good agreements between the simulated and measured data have been obtained from the field case by use of the improved PGB sand failure criterion, demonstrating its robustness and versatile applicability of predicting the dynamic and preferential wormhole network under various laboratory and field conditions.

Solvent-Based and Solvent-Assisted Recovery Processes: State of the Art

Summary Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.

Design of field‐scale cyclic solvent injection processes for post‐CHOPS applications

AbstractOil recovery factors in cold heavy oil production with sand (CHOPS) are typically lower than 15 %. Solvent‐aided processes, such as cyclic solvent injection (CSI) are common post‐CHOPS approaches, where wormhole networks could offer increased reservoir contact. However, grid block sizes in field‐scale simulations are much larger than the wormhole scale and large‐scale dispersivity values are assigned arbitrarily based on history matching. This work implements a statistical scale‐up workflow that facilitates the construction of coarse‐scale models for CSI simulation, whose relevant parameters are calibrated against simulation results using high‐resolution wormhole networks. The formulated workflow can be integrated with commercial reservoir simulators to effectively simulate solvent processes at multiple scales.Multiple injection scenarios are analyzed. Extended soaking periods may positively impact the ultimate recovery with a slower decline at later times, while a lower initial rate is observed. Interestingly, when an economic limit is imposed, the optimal soaking time is not necessarily the longest one. It depends on the trade‐off between extracting additional oil recovery at late times versus producing at a higher rate at early times. The analysis also reveals that the initial cycles contribute the most to the final recovery. In addition, when the amount of solvent available is limited, the results would support the strategy of injecting all the solvent in 1 single cycle, with an extended soaking period, rather than performing shorter consecutive cycles.

A new hybrid production optimization algorithm for the combined CO2-cyclic solvent injection (CO2-CSI) and water/gas flooding in the post-CHOPS reservoirs

In this paper, a new hybrid production optimization algorithm, namely, the steepest ascent‒particle swarm optimization (SA‒PSO), is developed to optimize the combined CO2-cyclic solvent injection (CO2-CSI) and waterflooding (WF) or gasflooding (GF) in the post cold heavy oil production with sand (CHOPS) reservoirs. The field-scale CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF performances are predicted by upscaling the laboratory tests and using the numerical simulations with the considerations of the wormholes propagation and foamy-oil flow. The net present value (NPV) is chosen as an objective function and maximized by adjusting the well controls, such as the bottom-hole pressure (BHP) and water/gas injection rate. The efficacies of the following three optimization methods are evaluated and compared: the steepest ascent (SA) method, particle swarm optimization (PSO), and SA–PSO. It is found that the SA‒PSO gives a higher global optimum NPV than the SA algorithm and requires fewer numerical simulation runs than the PSO. It combines the fast convergence of the SA algorithm and the global search of the PSO. It is also found that the CO2-CSI + GF has the highest NPV in the post-CHOPS reservoir among the three enhanced oil recovery (EOR) processes. For the CO2-CSI + GF, the gas injector should inject CO2 at the highest injection rate during the early cycles to displace the foamy oil but should be shut in during the late cycles to control the gas channeling. The optimum NPVs of the CO2-CSI, CO2-CSI + WF, and CO2-CSI + GF are achieved when the BHPs of the producers are maintained at the lowest pressure. It is uneconomical to apply the WF immediately after the CO2-CSI due to the early water breakthrough.

CO2-cyclic solvent injection (CO2-CSI) and gas/waterflooding in the thin post-CHOPS reservoirs

In this paper, a new combined CO2-cyclic solvent injection (CO2-CSI) and gasflooding (GF) process is proposed as an effective enhanced oil recovery (EOR) process in the post cold heavy oil production with sand (CHOPS) reservoirs. The synergy of the CO2-CSI and GF is explored and compared with that of the CO2-CSI and waterflooding (WF). A total of ten sandpacked laboratory tests were conducted to study and compare the production performances of the WF, CO2-CSI, combined CO2-CSI and GF/WF after the primary production. In the combined CO2-CSI and GF/WF processes, CO2/water is injected post, at the same time with, and prior to the CO2-CSI in the CSI + GF/WF, simultaneous (CSI + GF/WF), and GF/WF + CSI, respectively. Also the effect of CO2 injection rate is studied by injecting CO2 at three different flow rates in the CSI + GF. It is found that CO2-CSI + GF or CO2-CSI + WF performs better than the CO2-CSI or WF alone due to the extended foamy-oil flow. The combined CO2-CSI and WF outperforms the combined CO2-CSI and GF in terms of the heavy oil recovery factor (RF), heavy oil production rate, and cumulative gas-oil ratio (GOR). CO2 channeling is hindered by the subsequently injected water. In the combined CO2-CSI and GF, however, strong free-gas flow adversely affects the foamy-oil production in the later cycles of the CSI and in the subsequent GF. The best fluid injection timing in terms of the heavy oil RF is to inject CO2/water immediately after each cycle of the CSI production. A moderate CO2 injection rate gives the highest heavy oil RF of the CSI + GF. In conclusion, the combined CO2-CSI and GF/WF process is capable of recovering the remaining oil in the post-CHOPS reservoir.

Experimental Study of the Multiphase Flow of Sand, Viscous Oil, and Gas in a Horizontal Pipe

SummaryThis study provides horizontal-pipe pressure-drop and liquid-holdup measurements for three-phase flow of sand, viscous oil, and gas with a focus on slug flow (SL). We developed a correlation for predicting the liquid holdup and dimensionless pressure gradient in the presence of solids during SL.A multiphase-flow-loop facility with 1.5-in. (0.0381m) Schedule 80 polyvinyl chloride (PVC) pipes was designed and constructed to flow viscous oils ranging from 150 to 218 cp (0.15 to 0.218 Pa·s). Two-phase (221) and three-phase (88) data points were collected. A progressing cavity pump (PCP) was used to pump the complex mixture from a double-walled steel tank. Compressed air was used as the gas phase and 0 to 1 wt% of 180-µm diameter sand (test-section concentrations) was added to the flow. The facility had a clear test section for flow-pattern visualization and photography. Equipment issues and operational difficulties in the setup were identified during initial tests and rectified. Oil- and gas-flow rates, differential and absolute pressures, liquid holdup (both with and without the presence of solids), and fluid temperatures were measured, and flow-pattern observations were photographed. Gas and viscous-oil superficial velocities ranged from 0.1 to 10 m/s and from 0.1 to 1 m/s, respectively.We validated the setup by comparing actual single-phase liquid-pressure-drop measurements to an analytical expression for computing the pressure drop during single-phase viscous-oil flow. Sand was introduced into the system thereafter. We found that the presence of sand did not shift the flow-pattern boundaries appreciably and SL was the most commonly encountered flow pattern. As such, we focused on the SL region. Slow-motion photography and videography revealed that the presence of sand disrupted the sharp head and tail profiles in the liquid-slug body. Regression analysis using the observed data revealed that for SL of viscous oil and gas, the most-important dimensionless groups affecting both the holdup and the dimensionless pressure gradient are the fluid-velocity numbers and the Froude number. For three-phase SL of sand, viscous oil, and gas, the most-important dimensionless groups for affecting holdup in the presence of solids are the fluid velocity, Reynolds number, and Froude number in addition to the pipe-diameter number and the sand fraction in the flow stream. For dimensionless pressure gradient, the most-important dimensionless groups are the fluid-velocity numbers, the Reynolds and Froude numbers, and the input-liquid fraction.Slug-unit length was also measured, and the data were matched with an existing correlation. We also detailed the effect of sand on pattern behavior in each of the commonly observed horizontal-pipe multiphase-flow patterns using videography.To the best of our knowledge, this is the first recorded attempt at measuring pressure drop and liquid holdup in the presence of solids for the horizontal multiphase flow of sand, viscous oil, and gas. This work provides laboratory data/models that can support the characterization of the pressure drop and flow patterns experienced in horizontal wells completed using the process of cold heavy-oil production with sand (CHOPS) and other viscous-oil-producing wells.

Comparisons of Airborne Measurements and Inventory Estimates of Methane Emissions in the Alberta Upstream Oil and Gas Sector.

Airborne measurements of methane emissions from oil and gas infrastructure were completed over two regions of Alberta, Canada. These top-down measurements were directly compared with region-specific bottom-up inventories that utilized current industry-reported flaring and venting volumes (reported data) and quantitative estimates of unreported venting and fugitive sources. For the 50 × 50 km measurement region near Red Deer, characterized by natural gas and light oil production, measured methane fluxes were more than 17 times greater than that derived from directly reported data but consistent with our region-specific bottom-up inventory-based estimate. For the 60 × 60 km measurement region near Lloydminster, characterized by significant cold heavy oil production with sand (CHOPS), airborne measured methane fluxes were five times greater than directly reported emissions from venting and flaring and four times greater than our region-specific bottom up inventory-based estimate. Extended across Alberta, our results suggest that reported venting emissions in Alberta should be 2.5 ± 0.5 times higher, and total methane emissions from the upstream oil and gas sector (excluding mined oil sands) are likely at least 25-50% greater than current government estimates. Successful mitigation efforts in the Red Deer region will need to focus on the >90% of methane emissions currently unmeasured or unreported.

Estimation of CHOPS Wormhole Coverage From Rate/Time Flow Behaviors

Summary In wormholed reservoirs with cold-heavy-oil-production-with-sand (CHOPS) wells, regions covered by wormhole networks are estimated by analyzing rate/time flow behaviors along with pressure and sand-production data. In this work, the concept of effective wormhole coverage is proposed as a proxy of the drainage region of CHOPS wells with complex wormhole networks. The wormhole intensity is defined as the total length of wormholes per unit effective wormhole coverage. A CHOPS flow model is developed by use of the boundary-element method (BEM) to account for various boundary conditions, wormhole morphologies, and effects of wormhole dynamic growth. Transient pressure and rate responses calculated by the model are validated by comparing with analytical solutions and numerical simulations. Modeling results show that the effective wormhole coverage and wormhole intensity within the region dominantly affect the characteristics of pressure and rate/time behaviors, regardless of the detailed wormhole morphologies. Accordingly, dimensionless pressure and rate type curves are developed to match flow behaviors, such as wormhole linear- and transitional-flow regimes to estimate effective wormhole coverage of CHOPS wells with available field data. This work extends the literature with fast type-curve matching of pressure and rate/time behaviors instead of generally practiced numerical-simulation routines. A field case with rate and sand-production data is successfully analyzed to show great potential of applying the proposed approach to characterize CHOPS wormholes.

CO2-based heavy oil recovery processes for post-CHOPS reservoirs

Cold Heavy Oil Production with Sand (CHOPS) is currently the process of choice for recovery from unconsolidated solution-gas rich heavy oil reservoirs. Compared to waterflood and thermal recovery processes, primary processes such as CHOPS have relatively low energy and emission intensities; in other words, they can be considered as relatively ‘clean’ fossil fuel energy recovery processes. However, with recovery factors between 5 and 15% at the end of its economic life, there is a search for follow-up processes that yield additional oil from these reservoirs with continued low energy and emission intensities. One option is CO2-based enhanced oil recovery (EOR) processes – CO2 can lower oil viscosity and if some fraction of the injected CO2 is sequestered in the reservoir, then the process can be considered a CO2 storage process in addition to an oil follow-up recovery process. Here, we evaluate the energy return and CO2 sequestered in cyclic CO2 and cyclic CO2-hot water injection processes in a post-CHOPS heavy oil field. The results reveal that overall recovery factors can be raised through appropriate design of the CO2 follow-up process. Cyclic CO2 injection achieves an incremental 2.4% recovery factor (over four years of operation) with high energy return ratio whereas CO2-hot water processes achieve higher recovery factors with lower energy return ratios. In these processes, the amount of CO2 that remains sequestered in the reservoir is small, typically less than 5%. Thus, these EOR processes are not strong candidates for CO2 sequestration.

Characterization of gas-oil flow in Cyclic Solvent Injection (CSI) for heavy oil recovery

Cyclic Solvent Injection (CSI) has emerged as an effective follow-up process to the primary cold production, namely, Cold Heavy Oil Production with Sand (CHOPS). In this recovery process, the solvent is designed to maintain a strong nature of gas at in-situ conditions. As a result, the porous medium is spatially divided into two zones with differing fluid properties, which are gas zone, also called solvent chamber, and heavy oil zone. The CSI process is governed by the gas-oil flow as the solvent chamber is predominated by free gas-oil flow and the heavy oil zone by dispersed gas-oil flow (i.e. foamy oil flow).The gas-oil flow in CSI considerably differs from that in heavy oil solution gas drive, and therefore, needs to be investigated separately. The differences mainly arise from the origin of free gas. In CSI, the free gas originates at the solvent chamber, whereas in heavy oil solution gas drive, it evolves from solution gas. The free gas, in accordance with where it originates, yields occurrence time and quantity that have different dependency on the pseudobubblepoint pressure of oil. Consequently, the gas-oil flow in CSI results in the characteristics far more susceptible to the quantity of free gas and the nonequilibrium nature of foamy oil than heavy oil solution gas drive.This study is aimed at characterizing the gas-oil flow in CSI under the effects of pressure depletion rate as well as the solvent chamber. To fulfill this objective, the gas-liquid relative permeability curves were inferred with the use of numerical simulations and modified fractional flow models. The numerical simulations were carried out to history-match seven lab-scale CSI tests performed at different pressure depletion rates. The modified fractional flow models were applied to describe the foamy oil flow. The distinct characteristics of the gas-oil flow were examined based on sensitivity analysis and comparison to the previous findings on heavy oil solution gas drive.The results suggest that, at low pressure depletion rates, the gas-oil flow in CSI yield the characteristics that have also been observed in heavy oil solution gas drive. At sufficiently high pressure depletion rates, however, the free gas that exists even when the dispersed gas bubbles are immobile results in the different behavior of critical gas saturation and gas phase mobility. The solvent chamber misleads the gas-liquid relative permeability curves if the critical gas saturation is too high to properly describe the simultaneous flow of free gas and foamy oil. The solvent injectivity is also affected by the pressure depletion rate due to the foamy oil that has remained as unproduced in the solvent chamber during a previous production period.