Du, Xuan (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Zheng, Haora (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Wang, Xiaochun (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Hua, Xin (China Petroleum Technology Development Corporation, PetroChina Co. Ltd.) | Guan, Wenlong (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Zhao, Fang (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Xu, Jiacheng (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.)
Heavy oil reservoirs are generally unconsolidated and easy to produce sand during production
This paper describes a trial project to evaluate autonomous inflow control device (AICD) technology to better manage water production in a large heavy oil field in Colombia. The Cajua block is part of the Rubiales field is in the Llanos basin of Eastern Colombia, and has reserves estimated at 7.5 billion barrels. One of the main production challenges is the high water cut, or BSW, driven by strong aquifer flow in the underlying sands of the Carbonera formation. Many wells experience early water break-through and must be produced above 95% BSW for long periods of time. Horizontal wells typically produce up to 8000 barrels per day of total fluid with electric submersible pump (ESP) on cold production, and do not utilize any thermal recovery methods. The loosely-consolidated sandstone reservoir has variable water saturation and permeability, which has continuously frustrated operators'’ attempts to manage water production ever since the Rubiales field was first brought online in the 1980's.
In late 2018, a three well pilot project was initiated to evaluate the ability of inflow control technology to manage water influx at the sandface of the horizontal completions. Three wells in the Cajua block were equipped with AICD screens and swellable packers to evaluate oil production and water cut. The AICD technology works by limiting water inflow based on fluid viscosity. Each segment, or compartment, of the horizontal wellbore is isolated by swellable packers, and the AICD creates a higher or lower drawdown on the reservoir depending on the fluid properties, favoring the inflow of high-viscosity heavy oil over the low-viscosity water.
The early production results show that AICD completions can effectively manage water production by delaying water break-through and restricting water inflow from the reservoir. Each of the three trial wells responded positively to the autonomous ICDs, allowing engineers to produce heavy oil wells more effectively with lower cumulative water volumes.
This project marks the first implementation in South America of AICD technology with rate-controlled production (RCP) valves to manage water production in a heavy oil field. It is also the second application worldwide, after Canada, to show that AICDs can effectively to manage water cut in a heavy oil, cold-production scenario.
Abdelfatah, Elsayed (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Wahid-Pedro, Farihah (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Melnic, Alexander (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Vandenberg, Celine (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Luscombe, Aidan (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Berton, Paula (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Bryant, Steven (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada)
Waterflooding of heavy oil reservoirs is commonly used to enhance their productivity. However, preferential pathways are quickly developed in the reservoir due to the significant difference in viscosity between water and heavy oil, and hence, the oil is trapped. Here, we propose a platform for designing ultra-low IFT solutions for reducing the capillary pressure and mobilizing the heavy oil.
In this study, mixtures of organic acids and bases were formulated. Three different formulations were tested: (i) Ionic liquid (IL) formulation where bulk acid (4-dodecylbenzene sulfonic acid) and base (Tetra-
The IL and ABs formulation are acidic solutions with pH around 3. The ASBs formulation is highly basic with a pH around 12. Non of the formulations salted out below 14 wt% of NaCl. While conventional surfactant, SDBS, precipitated at salt concnetration less than 2 wt% of NaCl. The formulation solutions (1 wt%) have different optimum salinities: 2.5 wt% NaCl for ASBs, 3 wt% NaCl for IL and AB. Although IL and AB have the same composition and molar ratio of the components, their performances are completely different, indicating different intermolecular interactions in both formulations. Corefloods were conducted using sandpack saturated with Luseland heavy oil (~15000 cP) and at fixed Darcy velocity of 12 ft/day. A slug of 1 PV of each formulation was injected after waterflooding for 5 PV and followed by 5 PV post-waterflooding. In the hydrophilic sandpacks, IL and AB formulation produced an oil bank, consisting mainly of W/O emulsion, with oil recovery that is 1.7 times what was recovered by 11 PV of waterflooding solely. Majority of the oil was recovered in the 2 PV of waterflood following the IL slug. ASBs formulations produced O/W emulsions with prolonged recovery over 5 PV waterflooding after the ASB slug. The recovery factor for ASBs was 1.6 times that recovered for 11 PV of waterflooding only. In the hydrophobic sandpacks, The ASB formulation slightly increased the recovery factor compared to only waterflooding. While for IL and AB formulation, the recovery factor decreased.
This work presented a novel platform for tuning the recovery factor and the timescale of recovery of heavy oil with a variable emulsion type from O/W to W/O depending on the intermolecular interactions in the system. The results demonstrate that the designed low IFT solutions can effectively reduce the capillary force and are attractive for field application.
Cap rock integrity in Alberta's Oil Sands has gained increasing industry prominence over the years. A competent cap rock seal is a key mandate to subsurface containment assurance in thermal operations such as Steam Assisted Gravity Drainage (SAGD). Containment loss incidents in the past decade present substantial insights into regulating thermal development prospects as well as defining and benchmarking the industry practices in Alberta. Cap rock characterization and its response to high pressure and temperature in SAGD greatly influences the reservoir management strategy adopted by the operators. Constraints on the Maximum Operating Pressure (MOP) and safety factors are generally premised on tensile or shear cap rock failure probabilities.
This work integrates and analyzes key industry data from subsurface disciplines of geology, geophysics, geomechanics and reservoir engineering in characterizing regional Clearwater and Wabiskaw shale cap rocks in the Athabasca basin. A comprehensive analysis was conducted on sixteen (16) commercial oil sands projects and incident reports. Applications, reports and Supplemental Information Requests (SIRs) submitted to the Alberta Energy Regulator's (AER) published data and relevant literature was consulted to generate regional interpretations of the cap rock properties and industry approaches. A regional database of key properties including In-situ stresses, horizontal stress anisotropies, pore pressure gradients, and rock mechanical properties was compiled. In addition, regional failure modeling practices including numerical modeling assumptions, coupling, initial and boundary conditions and failure criteria are studied. Finally, common reservoir and cap rock monitoring techniques are explored.
Major conclusions from this study include regional interpretations of various risk factors affecting cap rock integrity in Oil Sands. Inferences from pooled industry data is used to generate a holistic interpretation of the Wabiskaw and Clearwater cap rocks. Intrinsic risk factors embedded in commonly practiced cap rock evaluation techniques, modeling and surveillance techniques in SAGD operations are identified alongside containment assurance programs commonly adopted by industry stakeholders. A summary of findings is provided at the end of this study for Operators to consider advancing their view on subsurface containment risk management.
Non-thermal-solvent and thermal-solvent based heavy oil recovery processes are technologies in which solvent is used as either the main or the secondary agent, in conjunction with heating, for bitumen viscosity reduction. In these processes a hydrocarbon solvent is injected into the reservoir and produced back with the recovered bitumen. A fraction of the injected solvent is retained in the reservoir at an equilibrium state as gas and liquid phases. Since the cost of injected solvent in these processes is a major portion of the operating cost, recovery of the retained solvent from the reservoir at the end of bitumen depletion stage results in recovery of significant capital and thus improvement of the process economics.
Imperial-ExxonMobil have been optimizing the existing and developing new recovery technologies to improve the efficiencies, economics and environmental performance of heavy oil production operations. Recent focus has been on developing solvent based recovery processes through an integrated research program that includes fundamental laboratory work, advanced numerical simulation studies, laboratory scaled physical modeling, and field piloting. The research program aims at in-depth investigation and understanding of process physics and mechanisms to allow evaluating and optimizing process performance.
In this paper, development of a new method for recovery of the retained solvent from the reservoir at the end of the bitumen depletion stage is introduced. This method takes advantages of solvent vapor-liquid thermodynamic equilibrium to strip the retained solvent from the reservoir. A stripping gas is injected and circulated in the bitumen depleted chamber to vaporize and recover the retained solvent to the surface. The reservoir modeling results show that this method is very effective and efficient in accelerating recovery of the retained solvent. The physical modeling experimental data confirms the effectiveness of this method. Field pilot data from a solvent assisted recovery process are presented which demonstrate solvent recovery efficiency using continuous steam injection.
Penny, Scott (Petrospec Engineering Inc.) | Karanikas, John M (Salamander Solutions Inc.) | Barnett, Jonathan (Salamander Solutions Inc.) | Harley, Guy (Salamander Solutions Inc.) | Hartwell, Chase (Petrospec Engineering Inc.) | Waddell, Trent (Petrospec Engineering Inc.)
Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in two different horizontal cold-producing heavy oil wells in Alberta is presented.
The first field case study discusses the application of electric heating in a mature, depleted field as a secondary recovery method while the second case study examines a virgin heavy oil reservoir, where cold production by artificial lift was economically challenged. The completion, installation, expected and actual results of both cases studies are compared and contrasted.
Both field deployments demonstrate the benefits and efficacy of applying downhole electric heating. In the case of the mature depleted field, electric heating resulted in a 4X-5X increase in oil rate, sustained over a period of close to two years. The energy ratio of the heating value of the incremental produced oil to the injected heat was slightly over 7.0. In the virgin heavy oil field, electric heating reduced the viscosity of the oil in the wellbore from time zero, which allows for higher rates of oil production along the complete length of the long horizontal lateral at higher, if desired, bottomhole pressures than in a cold-producing well. This degree of freedom may ultimately allow for an operating policy that suppresses excessive production of dissolved gas, thereby helping conserve reservoir energy. Early production data in this field show 4X-6X higher oil rates form the heated well than from the cold-producing benchmark well in the same reservoir.
Numerical simulation models, which include reactions that account for the foamy nature of the produced oil and the downhole injection of heat, have been developed and calibrated against field data. The models can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method, which is crucially important in the current low oil price scenario. The same models can also be used during the execution of the project to explore optimal operating conditions and operating procedures.
Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs in Alberta as well as around the world.
Mature heavy oilfields in the Northern Peruvian Jungle have produced oil for more than 40 years under primary recovery mechanisms (cold methods). As these fields are exploited by a strong water drive assisted with ESPs, total oil production has surpassed more than 1 billion barrels of oil with an average 15% primary recovery factor; ultimate recovery is expected to account for 17% at an economic limit of approximately 98% water cut. According to the
This study explores the development options (technical an economic) to produce heavy oil resources at commercial rates and showcases three optimization scenarios of higher recovery efficiency (additional 5%, 10% and 15% RF) utilizing current technology and sensitizing their economic variables with the main objective of increasing the net present value at the basin level. This is achieved by exploring and validating synergy strategies available in the basin and proposes investment for the Norperuano pipeline revamp to pump light oil/diluent to heavy oilfields (e.g Block 67) and make transportation of volumes currently classified as resources feasible. Lastly, this paper shows the current royalty framework in the Loreto region on a block basis and explores the financing alternatives to foster development and exploration activities in the North Peruvian Jungle heavy oilfields.
The workflow starts with identifying heavy oil development strategies, prioritizing and selecting the most appropriate technologies to optimize production performance and increase recovery efficiency; then, infrastructure options and financing alternatives are carefully reviewed to ensure heavy oil is produced with an appropriate amount of diluent. Finally, royalty and other tax incentives are suggested to ensure a profitable exploitation of heavy oil resources. Typically, primary recovery factors for heavy oilfields range between 10 to 15% with several alternatives for development such as multilateral drilling, steam flooding and HASD which would at least double production rates and increase recovery factors by 10% to 15%. Pilot tests of thermal recovery methods are strongly recommended for some fields in early development stage such as the Bartra field in Block 192 and the Raya and Paiche fields in Blocks 39 and 67 respectively. In order to handle new production rates, modifications to the Norperuano pipeline are proposed; additional in-situ loops and a parallel new pipeline are suggested, not only to ensure diluent/light oil transportation to supply the heavy oilfields, but also to increase transportation capacity of diluted oil to surface storage facilities and to the Refinery Complex in Talara; located on Peru's northern Pacific coast which is currently undergoing an expansion from 65,000 bopd to 95,000 bopd due by November 2020.
Assuming the first two conditions are met (the increase of production rates and recovery factors, and the egress constraint is no longer relevant) the profitability of the project at the basin roll-up level must be tested with a reserves model with inputs such as production rates by block, operating and capital expenditures for the different reserves/production wedges, royalty rates and taxes. The model must be consistent with the development program proposed by the operators in the region and be run at different pricing scenarios to stress-test the break-even value at several levels.
Gasser-Dorado, Julien (IFP Energies nouvelles) | Ayache, Simon Victor (IFP Energies nouvelles) | Lamoureux-Var, Violaine (IFP Energies nouvelles) | Preux, Christophe (IFP Energies nouvelles) | Michel, Pauline (IFP Energies nouvelles)
SAGD is commonly used as a thermal EOR method to produce heavy oil. However it suffers from the production of acid gases formed by aquathermolysis chemical reactions that occur between the steam, the sulfur-rich oil and the mineral matrix. The objectives of this paper are to take advantage of a comprehensive chemical model coupled to compositional thermal reservoir simulations to predict and understand the H2S production variation at surface according to the type of reservoir.
Thermal reservoir simulations coupled to both a SARA based 10-component / 5-reaction chemical model fully calibrated against laboratory data and a compositional PVT are used to simulate SAGD processes on heavy oil fields in Athabasca, Canada. Numerical results are then analyzed to provide a comprehensive analysis of the mechanisms leading to in-situ H2S generation and its production at wellheads based on compositional thermal simulations coupled to a fully laboratory calibrated SARA-based chemical model. Composition of the pre-steam, post-steam and produced oil are compared to understand the effect of the aquathermolysis reactions. The impact of heterogeneities on H2S production both in-situ and at surface can also be observed and explained, especially the variations in vertical permeability. Then simple reservoir models with two facies are used to further understand the impact of heterogeneities on H2S production at surface. Overall heterogeneous cases show important changes in the temperature distribution, fluid flows, reactions kinetics and steam chamber shape that lead to H2S production variations at surface. This detailed description of the involved mechanisms in acid gases production will allow operators to better forecast their H2S risks according to their reservoir properties.
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