Oil production from shale and tight formations will increase to more than 6 million barrels per day (b/d) in the coming decade, making up most of total U.S. oil production (> 50%). However, achieving an accurate formation evaluation of shale faces many complex challenges. One of the complexities is the accurate estimation of shale properties from well logs, which is initially designed for conventional reservoirs. When we use the well logs to obtain shale properties, they often cause some deviations. Therefore, in this work, we combine cores and well logs together to provide a more accurate guideline for estimation of total organic carbon, which is primarily of interest to petroleum geochemists and geologists.
Our work is based on Archie's equation. Resistivity log will lead to some incorrect results, such as total resistivity, when we follow the conventional interpretation procedure in well logs. Porosity is another complex parameter, which cannot be determined only by well log, i.e. density, NMR, and Neutron log. Therefore, the flowchart of TOC calculation includes five main parts: (I) the shale content calculation using Gamma log; (II) the determination of shale distributions using Density and Neutron logs and cross-plot; (III) the calculation of total resistivity at different distribution types; (IV) obtaining porosity using core analysis, NMR and density logs; and (V) the calculation of TOC from modified Archie's equation.
The results indicate that the shale content has a strong effect on estimation of water saturation and hydrocarbon saturation. Especially, the effect of shale content is exacerbated at a low water saturation. A more accurate flowchart for TOC calculation is established. Based on Archie's equation, we modify total resistivity and porosity by combining Gamma Log, Density Log, Neutron Log, NMR Log, and Cross-plot. An easier way to estimate porosity is provided. We combine the matrix density and kerogen density together and obtain them from core analysis. Poupon's et al. (1954) laminar model has some limitations when applying in shale reservoirs, especially at a low porosity.
Literature surveys show few studies on the flowchart of TOC calculation in shale reservoirs. This paper provides some insights into challenges of well logs, core analysis in shale reservoirs and a more accurate guideline of TOC calculation in shale reservoirs.
Two-phase oil/water relative permeability measurements were conducted at ambient and high temperatures in two different rock-fluid systems; one using a clean Poly-Alpha-Olefin (PAO) oil and the other with Athabasca bitumen. The tests were performed in a clean sand-pack with the confining pressure of 800 psi, using deionized water as the aqueous phase. Both the JBN method and the history match approach were utilized to obtain the relative permeability from the results of isothermal oil displacement tests. The contact angle and IFT measurements were carried out to assess any possible wettability alteration and change in fluid/fluid interaction at higher temperatures.
Results, Observations, Conclusions: The results of the clean system using the viscous PAO oil confirmed that the two-phase oil/water relative permeability in this ultra-clean system is practically insensitive to the temperature. The slight variation in oil endpoint relative permeability, especially at ambient condition, was attributed to variations in the packing of sand. It was found that the history matching derived two-phase relative permeability from the highest temperature test provides reasonably good history matches of the other displacements that were conducted at lower temperatures. In addition, it is shown that the JBN approach based relative permeability curves show larger variations, primarily due to insufficient volume of water injection at lower temperatures, which makes the practical residual oil saturation much higher than the true residual. In contrast with the ultra-clean system, the results obtained with bitumen showed much larger variations in relative permeability with temperature.
Most of the reported studies involving history matching approach treat the low-temperature measurements as the base case and show that changes in relative permeability are needed to history-match the tests at higher temperatures. We have shown that the displacement done at the highest temperature provides a more reliable estimate of the relative permeability and, in some cases, this relative permeability can successfully history match tests done at lower temperatures. In view of the impracticality of injecting sufficient water to reach close to real residual oil saturation at low temperatures, it would be better to obtain relative permeability data at high temperatures for characterizing the two-phase flow behavior of viscous oil systems.
Lolla, Sri Venkata Tapovan (ExxonMobil Upstream Research Co) | Bailey, Jeffrey (ExxonMobil Development Co) | Costin, Simona (Imperial Oil Resources Ltd) | Hons, Michael (Imperial Oil Resources Ltd) | Liu, Xinlong (Imperial Oil Resources Ltd) | Yam, Helen (Imperial Oil Resources Ltd) | Akhmetov, Arslan (ExxonMobil Canada Properties) | Hayward, Timothy (Imperial Oil Resources Ltd) | Brisco, Colin (Imperial Oil Resources Ltd)
Continuous subsurface surveillance is important for heavy oil in-situ recovery processes where induced stresses in the overburden can compromise the integrity of the wellbores. Wellbore failure may lead to the undesirable loss of fluids into the overburden. In recent years, there has been a rapid growth in the use of Passive Seismic monitoring systems to aid in subsurface surveillance activities, with the ultimate goal of detecting potential integrity issues as early as possible. However, the massive volume of data recorded by these instruments is time-consuming and error-prone to process manually. This paper introduces EMMAA (ExxonMobil Microseismic Automated Analyzer), an automated workflow to reliably process continuous microseismic data, detect subsurface integrity issues, and ultimately reduce the latency in responding to wellbore integrity issues.
A novel cloud-based technology for managing microseismic data is briefly described. The seismic waveforms, recorded by a distributed array of geophone receivers, are automatically analyzed to determine the type and source of subsurface disturbances (
First, novel frequency-domain and deep learning analyses are used to distinguish noisy signals from the seismic waveforms such as compressional and shear waves produced by the events. Next, the location of the event is calculated and its seismic attributes are computed. Finally, the type and severity of the seismic event are determined by an event classifier.
The performance of the automated workflow is examined in the context of accurate detection of casing failures in a heavy oil Cyclic Steam Stimulation (CSS) application. The event features that distinguish casing breaks from other seismic events are described. It is shown that the methodology is able to achieve a high detection rate when back-tested against a historical data-set of known casing failures. False positives are adequately contained by preventing waveforms of electrical or mechanical noise from being processed.
In a production environment, the event processing workflow is run on distributed servers and analyzes triggered seismic data in real-time. Depending on the severity of the microseismic events detected, operators are immediately alerted via email and text messages, so that remedial actions may be swiftly initiated. The utility of this integrated system is further exemplified by the massive reduction in the time taken to detect casing breaks—from up to 36 hours historically, down to less than one hour in most instances.
Extensions of EMMAA that enable the detection of a wide variety of microseismic events are also discussed. These events include surface casing slips that occur at the casing shoe, cement de-bonding events near the wellbores, and events indicative of potential fluid migration in the overburden.
Costin, Simona (Imperial Oil) | Smith, Richard (Imperial Oil) | Yuan, Yanguang (Bitcan Geoscience and Engineering) | Andjelkovic, Dragan (Schlumberger Canada) | Garcia Rosas, Gabriel (Schlumberger Canada)
Open-hole mini-frac tests are seldom performed in the Athabasca and Cold Lake oil sands due to the complexity of operations. In this paper we present the results of open-hole injections tests performed in Cold Lake, Alberta (AB), Canada. The objective of the injection tests was to assess the in-situ stress condition in the Cretaceous Colorado Group. The injection tests results combined with the run of formation image logs (FMI) before and after the injection have enabled not only the determination of the in-situ minimum stress in the rock, but also the full 3-D stress tensor, along with the orientation and inclination of the hydraulic fracture. The tests were performed in IOL 102/08-02-066-03W4 (N10 Passive Seimic Well, 'PSW'). The injection tests have revealed that the vertical stress in the area is the in-situ minimum stress, consistent with previous measurements. The hydraulically-induced fracture has sub-horizontal to moderate dip angle, mostly owing to the preexisting fabric of the rock, and peaks in the general NE-SW direction. Numerical modeling of the in-situ stresses has shown that the values of the vertical and the minimum horizontal stresses are close, with the vertical stress consistently being smaller than the minimum horizontal stress in all tested zones.
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.
Optimizing steam-assisted gravity drainage (SAGD) performance in oil sands reservoirs relies on the quality of steam allocation decisions made across the well inventory. With finite facility steam generation capacity, SAGD producers are typically challenged with identifying the true opportunity cost of allocating steam volumes based on well performance. This paper presents a novel technique to inform steam allocation decisions and managing SAGD reservoir pressures in service of optimizing production and consequently improving the economic performance of the asset through smarter SAGD field development planning.
The concept of marginal steam-oil-ratio (mSOR) is introduced as a method of guiding steam allocation decisions. Marginal SOR is defined as the cold-water equivalent volume of steam required to produce the next marginal barrel of bitumen from the production system in a steam constrained environment. The metric represents the opportunity cost of deploying a barrel of steam to the next best alternative in steam allocation decisions. Dynamic quantification of mSOR over the plausible range of operating pressures for each producing entity (PRDE) in the inventory (such as a well group or drainage area) is critical to optimally allocating steam when faced with reservoir challenges such as reservoir complexity and heterogeneity and transient reservoir behaviors such as thief zone interaction.
This paper prescribes methodologies to analytically and empirically quantify mSOR for a SAGD production system. Additionally, application of the concept if field production optimization is discussed under the context of integrated production modeling and constrained flow network optimization problems. A case example of applying mSOR to guide steam allocation decisions at ConocoPhillips' Surmont SAGD asset is presented under a steam constrained environment. The mSOR guided solution is validated using brute-force enumeration of steam allocation outcomes in the production system to prove production optimality. The results from this dynamic steam allocation strategy guided by mSOR characterization show significant improvements in field oil rates, field steam management efficiency and consequently the economic value of the SAGD asset.
Aminfar, Ehsan (University of Calgary) | Sequera-Dalton, Belenitza (University of Calgary) | Mehta, Sudarshan Raj (University of Calgary) | Moore, Gordon (University of Calgary) | Ursenbach, Matthew (University of Calgary)
The injection of air into mature steam chambers is a promising technology to reduce the steam-to-oil-ratios (SOR) in late stages of the Steam-Assisted-Gravity-Drainage (SAGD) recovery process in Athabasca oil sand reservoirs in Alberta, Canada. Air injection allows sustaining steam chamber pressures with reduced steam injection rates. The steam capacity that becomes available due to the replacement of steam with air in mature well-pairs or pads could serve new pads optimizing steam utilization and decreasing the overall environmental footprint of the project. A novel large scale three-dimensional (3-D) physical model was designed to evaluate the prospect of the "hybrid" air and steam injection technology in a SAGD configuration utilizing up to three well-pairs. This paper discusses the 3-D model design, commissioning, experimental procedure and main results of the first tests.
For each test, the 3-D model was packed with a low oil saturation core or lean zone, representing the reservoir portion swept by steam, and a high oil saturation core or rich zone representing the un-drained zone between two coalesced steam chambers. These zones were made with preserved native "lean" and "rich" cores from Athabasca reservoirs. Once the model was packed, it was placed inside a pressure jacket where it was pressurized to reservoir pressure. Steam was injected into the model to develop a representative steam chamber in the lean zone. Once steam conditions were attained in the lean zone, steam injection was switched to air injection. Temperatures distributed in the 3-D model as well as injection and production pressures and produced gas compositions were monitored constantly and recorded during the test. Produced liquid samples were regularly captured and stored for subsequent analysis. Post-processing analyses of produced fluids and residual extracted core material allowed for determination of clean-burned zones, material balance, upgrading of the produced bitumen samples and efficiency of the process.
High peak temperatures, gas compositions, clean-burned sand in post-test cores and significant oil production indicate the development of a high temperature combustion front in the 3-D experiments. The test results confirm the injection of air into mature SAGD chambers is a very promising method not only to reduce the cumulative steam-to-oil-ratios (CSOR) and to sustain the steam chamber pressures but also to increase oil production in SAGD late life.
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.
Steam Assisted Gravity Drainage (SAGD) is a complex process and often requires more control relative to conventional applications during production operations. Flow Control Devices (FCDs) have been identified as a technology that offers improved efficiency of the process while simplifying the operations. The first FCD completions were installed in SAGD wells in Canada over a decade ago with the intention of improving the steam chamber conformance and reducing the steam-oil ratio (SOR). While it is widely understood that FCD completions, for the most part, have helped achieve the desired uplift for SAGD producers, further optimization could be made on future completion designs and operation strategy by looking at actual performance data from previous installations. The objective of the study was to obtain key design parameters and considerations for future FCD completion designs.
The majority of FCD completions in MacKay River were tubing deployed, installed in previously producing wellbores (retrofit). This study looks at 11 wells that were completed with a Baker Hughes FCDs. The analysis was broken down into 2 segments: production analysis and modelling. Production strategy implemented for each well was taken into account to eliminate variances. The modelling used a combination of steady state simulation (presented in this paper) and numerical simulation (to be presented in part II).
The study showed that TD FCDs improve the performance of SAGD well pairs when implemented in the appropriate candidate wells. An important outcome was the development of a candidate wells’ selection criteria, to ensure the retrofit completion improved performance and did not exacerbate other problems. Furthermore, design consideration were identified to improve the performances of future TD FCD installations.