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Collaborating Authors
Results
An Experimental Investigation into Sand Control Failure Due to Steam Breakthrough in SAGD Wells
Mahmoudi, M.. (RGL Reservoir Management Inc.) | Fattahpour, V.. (RGL Reservoir Management Inc.) | Roostaei, M.. (RGL Reservoir Management Inc.) | Kotb, O.. (University of Alberta) | Wang, C.. (University of Alberta) | Nouri, A.. (University of Alberta) | Sutton, C.. (RGL Reservoir Management Inc.) | Fermaniuk, B.. (RGL Reservoir Management Inc.)
Abstract In Steam Assisted Gravity Drainage (SAGD) projects, it is essential to heat the reservoir evenly to minimize the potential for the localized steam breakthrough. Steam breakthrough can cause erosive damage to the sand control liner by the flow of high-velocity wet steam, and, in extreme cases, can compromise the mechanical integrity of the liner. This research investigates the sanding mechanism during the high-quality steam injection into the SAGD production wells. A large-scale Sand Retention Test (SRT) was used to investigate the role of steam breakthrough in the sand control performance. Produced sand and pressure drops along the sand-pack were the main measurements during the tests. The test procedure and test matrix were designed to enable the examination of the impact of steam breakthrough on sand production for different steam rates. Two possible sanding mechanisms are postulated in steam breakthrough events: (1) local grain disturbance caused by the high-velocity steam near the liner, (2) effect of the complex phase behavior of the steam and the subcool level. Two different testing procedures were designed to examine these mechanisms. The local grain disturbance mechanism was investigated by injecting air at a wide range of velocities. Results indicate that this mechanism could not lead to a significant sanding when there is a bit of effective stress near the liner. Hence, it looks like that the steam velocity poses a higher risk in early stages of SAGD production when the near-liner stress is very low. The effect of high-pressure high-temperature (HPHT), low- to high-quality steam flow and the subcool level will be investigated in the next phase of the study. This work addresses the effect of high-quality steam breakthrough on the sand control performance of the liner in SAGD producer wells. The findings in this paper help the researchers to direct their research to better understand the steam breakthrough. This research will eventually help the engineers in their liner design and evaluation for the entire wellbore life cycle as the near-well stress evolves.
- North America > United States (1.00)
- North America > Canada > Alberta (0.72)
Abstract This paper presents the results of an experimental investigation to determine the mechanisms of pore plugging and permeability reduction near SAGD screen liners. The aim is to arrive at a liner design that maximizes wellbore productivity without compromising the sand control function of the liner. We set up a large-scale Sand Retention Testing (SRT) facility that accommodates a multi-slot liner coupon at the base of a sand-pack with representative grain shape and particle size distribution (PSD) of typical oil sands. Brine is injected at different flow rates and pressure differences across the coupon and the sand-pack as well as the mass and PSD of the produced sand and fines are measured during the test. Further, the PSD and concentration of migrated fines (<44 microns) along the sand-pack are determined in a post-mortem analysis. The testing results are used to assess the effect of slot size and slot density on the sand control performance as well as pore-plugging and permeability alterations near the sand-control liner. We observed that the slot size, slot density and flow rate highly affect the concentration and PSD of produced fines as well as accumulated fines (pore clogging) above the screen. For the same flow rates and total injected pore volume, wider screen aperture and higher slot density result in lower fines accumulation above the screen but more sanding. Further, the variation of slot density alters the flow convergence behind the slots, hence, the size and concentration of mobilized fines. Results indicate that higher fines concentration near the screen reduces the retained permeability, hence, lowers the wellbore productivity. This paper provides a new insight into pore plugging and fines migration adjacent the sand control liner. It also introduces a new testing method to optimize the design of sand control liners for minimum productivity impairment in SAGD projects.
- North America > United States (1.00)
- North America > Canada > Alberta (0.70)
- Geology > Mineral > Silicate > Phyllosilicate (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.36)
- North America > United States > Colorado > Spindle Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- Well Completion > Sand Control (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract A thermally insulated coiled tubing is permanently inserted in a horizontal heavy oil producer well and used to circulate hot oil (or water) in the well to heat by conduction the vicinity of the liner, where the drawdown is the most important. This process can be used in non-thermal wells and improves heavy oil field production with a limited quantity of energy. This paper presents the typical completion applied for this EOR process, the well integrity concerns due to high temperature and the calculated oil production increase that is confirmed by field application. The insulated coiled tubing is inserted into the horizontal well up to the well-toe. The production tubing is installed parallel to the insulated coiled tubing. The process is pumping hot oil at 230°C (or water) through the insulated coiled tubing. The heated oil is circulating from the well-toe back to the well-heel in the liner and heat the reservoir by conduction. This energy delivered to the reservoir will reduce the oil viscosity within a few meters from the liner and allow lower pressure drop. A transient thermal model has been developed to model this EOR process. The equations on which the model has been built are Darcy's law, the continuity of the flow and the energy balance. Some assumptions were taken to simplify the model such as constant reservoir properties over space and time. The model provides the temperature along the liner with max temperature at the toe and min temperature at the heel as well as the radial temperature in the reservoir. It models also the extra oil production allowed by the process. The temperature involved on the critical parts of the completion remain low and allow to apply this EOR on non-thermal wells. The field monitoring (temperature and net oil production) of the first pilots in Canada have confirmed the model results. The energy consumption requested is approx. 400kW, ten to twenty times lower than typical steam injection process. This process is not a competitor for steam injection but a good way to improve the production of heavy oil well with low CAPEX and low OPEX for specific fields where steam injection is not efficient like fields with thin reservoir. In this tough period for the oil industry, this technology can be applied on existing producer wells without drilling injector wells. The combination of this process with waterflooding is a win-win association. Waterflooding brings the driven mechanism to the reservoir and the thermal process allows better oil flow at the well.
Abstract Over the past few years, an increasing number of operators in steam assisted gravity drainage (SAGD) in situ recovery of bitumen in the Alberta Oil Sands are becoming interested in the use of flow control devices (FCDs). Initial field trials by some operators of these devices have shown promise in improving steam chamber conformance, reducing incidences of steam breakthrough, high vapour production, and in addressing liner reliability concerns related to steam jetting. While the application of FCDs is well-established in the conventional oil and gas industry to control gas and water coning, there are still a number of questions on how to implement FCDs optimally in SAGD. One major difference in the application of FCDs in SAGD compared to the conventional oil and gas industry is the high temperature environment with steam and elevated erosion risk. The purpose of this paper is to present some practical considerations for the selection of FCDs and optimal completion FCD design for SAGD applications. In the first section, a discussion is presented on how to compare the performance of different flow control devices. Most devices have not been tested for SAGD, and there is a need for more comprehensive testing. The focus of the second section is on practical considerations for the installation of FCDs in a SAGD injection and production wells.
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Surmont Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Firebag Oil Sands Project > Wabiskaw-McMurray Formation (0.98)
- North America > United States > Arkansas > Stephens Field (0.93)
SAGD Production Observations Using Fiber Optic Distributed Acoustic and Temperature Sensing: "SAGD DAS - Listening To Wells to Improve Understanding of Inflow"
MacPhail, Warren (Devon) | Kirkpatrick, James (Devon) | Banack, Ben (Halliburton) | Rapati, Bryan (Halliburton) | Asfouri, Alex Ali (Halliburton)
Abstract Performance optimization of steam assisted gravity drainage (SAGD) well pairs requires awareness of unique and sometimes complex downhole processes. Reservoir monitoring tools commonly used to characterize the downhole pressure and temperature environments include thermocouples, pressure gauges, and discrete or distributed fiber-optic sensors. Distributed temperature sensing (DTS), the most common fiber-optic measurement used for SAGD reservoir monitoring, has been widely adopted for SAGD production monitoring due to its ability to accurately measure a wide variety of temperatures in harsh environments. High-measurement density along the entire SAGD well length has proven to be useful for both production optimization (Krawchick et al. 2006) and well-integrity applications. Though DTS monitoring is a primary downhole measurement tool for thermal production, other sensors may further characterize the nature of SAGD well performance when used in conjunction with DTS. Alone, temperature and pressure measurements may not yield a complete understanding of the inflow contribution in SAGD production wells. For instance, the effects of complex heat transfer may mask reservoir temperatures. Additionally, high temperatures are not always indicative of inflow and cooler liner temperatures may not signify the absence of production contribution. Distributed acoustic sensing (DAS), which is used to measure acoustic frequency and intensity in 1-m intervals along the length of a fiber-optic line, is another downhole measurement tool currently being evaluated for its ability to provide additional downhole wellbore information. Although DAS has been commonly used to characterize the acoustic environment in hydraulically fractured horizontal wells (MacPhail et al. 2012, Holley et al. 2015), it has not been extensively applied in SAGD well pairs. This paper shares select DAS and DTS monitoring data from a pilot well, the results of which improved the operator's understanding of the nature of the SAGD production. In late 2012, Devon Canada installed DTS multi-mode fiber in several production wells at SAGD assets in the McMurray Oil Sands. Single-mode fiber utilized for DAS were deployed in conjunction with multi-mode fiber, allowing simultaneous logging of DTS and DAS data throughout the wellbore. Temperature and acoustic datasets were obtained at different representative flow conditions, including stable production, rate step-down, early time shut-in, and well startup. The combined analysis of DTS, DAS, and surface production data shows that DAS was able to identify steam flashing and qualitatively define production inflow contribution and gas/liquid composition. Due to the complex, bi-directional flow in the trial well, some of these conclusions would not have established without the observations obtained from DAS monitoring.
Abstract Horizontal wells have been widely used to significantly increase reservoir exposure in a wide range of conventional and unconventional oil and gas recovery applications, including tight-rock and multi-stage fracturing, offshore, primary and thermal heavy oil projects. In the heavy oil and bitumen reservoirs of the Western Canadian basin, horizontal wells have been extensively employed in Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) in-situ recovery projects. In SAGD applications, the lateral sections of these horizontal wells are generally completed with various types of sand control systems, including slotted liners, Wire Wrapped Screens (WWS) and premium screens with a growing percentage incorporating some form of downhole injection or production Flow Control Devices (FCD). Given the relatively shallow depths, low reservoir pressures and high fluid rates of these applications, these horizontal wells are often constructed with relatively high build rates and large diameter tubulars. In an effort to improve project economics, well designs with increasingly longer lateral sections are being pursued. In an effort to reduce potential damage during installation, engineering assessments are commonly conducted to ensure that the structural capacity of these liners exceeds the demand of the combined installation loads caused by liner-wellbore interaction and liner string buoyant weight, often with consideration of a suitable safety margin. To date, given the number of influential parameters, the complex nature of the analysis and corresponding computational demands, methods which employ significant simplifications, such as soft-string torque and drag (T&D) models, have been commonly used to assess liner installation loads. In addition, it appears that the current commercial soft- and stiff-string T&D analysis tools do not consider the nonlinear load capacity envelopes of the sand control liners in the evaluation to assess the potential damage under combined loading during installation. Advanced numerical methods, such as Finite Element Analysis (FEA), have also rarely been employed to evaluate the liner installation loads due to the complex nature of this problem. This paper presents an advanced stiff-string T&D analysis approach developed using the commercial FEA program Abaqus. To demonstrate the application of this approach, several example cases are presented simulating the installation of the slotted liner design into a horizontal SAGD well. In these T&D analyses, wellbore and tubulars were modeled using pipe elements which accurately capture various geometric parameters and associated mechanical responses of the tubulars. Contact interaction and the clearances between the tubulars and the wellbore were modeled. Different friction factor (FF) values were assigned to the cased and open hole sections of the well. By incorporating the load capacity envelopes of the specific slotted liner design into the analysis, this paper demonstrates how this methodology may be applied to assess the load responses and potential damage risks associated with running large diameter liners into high build rate extended-reach horizontal wells. The approach presented in this paper may be expanded to various tubular, completion equipment and drill string running applications.
- North America > United States (1.00)
- North America > Canada > Alberta (0.47)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.68)
Abstract Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery process wherein a long horizontal steam injection well is located above a long horizontal production well. Injected steam forms a steam chamber above the SAGD well pair, heating the reservoir rock and reservoir fluids. Heated oil (or bitumen) plus condensed steam flow down the sides of the steam chamber towards the production well. The condensed steam and bitumen are then lifted to surface with a downhole pump or by gas lift. Due to a rapidly increasing number of SAGD well pairs, Suncor required a tool that could accurately model these challenging thermal production wells. Nodal analysis for well performance is based on the principle that reservoir inflow and wellbore outflow can be independently characterized as functions of flow rate and pressure. Nodal analysis is used to design new wells and optimize production or injection on existing wells. Wellbore simulations are cheaper than instrumentation, meters or single well tests. Well evaluation software is the most popular engineering package in Suncor's production engineering toolkit because it is very accurate and easy to use. Over the past few years Suncor worked with their software provider to develop nodal analysis for SAGD production wells. Suncor can now model SAGD producers with electric submersible pumps (ESPs) and gas lift with a high degree of confidence. The new SAGD nodal models quite closely match production rates, plus surface and downhole pressure and temperature data. Reliable and rigorous SAGD nodal models enable improved decisions with respect to SAGD field development and production optimization. Nodal analysis can be used as a predictive tool for production optimization, or for a better understanding of what is happening downhole with respect to temperature, pressure, and flow distribution within the wellbore. This paper is a logical continuation of SPE 170054, Nodal Analysis for SAGD Production Wells with ESPs (ref 1). The main difference between modeling wells with gas lift rather than mechanical lift is that the gas lift models also account for steam lift. Steam lift occurs when some of the produced water (PW) in the emulsion flashes to steam as pressure is reduced. The resulting vapour significantly augments gas lift and reduces lift gas requirements.
Abstract JACOS’ Hangingstone Demonstration Project has been in operation since 1999. The company has used the 10,000 bbl/D facility as a foundation for learning and refining SAGD processes and operations. The 24 operational well pairs, with 15 years of production has provided valuable insight into the performance of different liner completion types and operational control mechanisms. Data from the Demo project has provided the basis for a liner test strategy and liner design for application at JACOS’ Phase 1 Hangingstone Expansion project. First steam is expected in late 2016. All of the 24 operating well pairs at the Demo project have concentric tubular designs, but varying liner completion types. One well pair is completed with MeshRite, 13 well pairs with wire wrap screens and 10 well pairs are completed with slotted liners of varying slot sizes. With a relatively strong surveillance program, the flow distribution (inflow), subcool control, hydraulics and operability for each of the well pairs were carefully analyzed. The performance of wells with MeshRite, wire wrap screen and slotted liners will be presented. The analysis provided insight into what was successful in the field and provided a strong basis for the test design. As part of the expansion project, field performance data from the six phases of the Demo project, coupled with particle size analysis, flow testing and thermal performance analysis, guided JACOS to select slotted liners for all injector wells. For the producers, 27 wellbores were completed with wire wrap screens and five wellbores with MeshRite liners, for a total of 32 well pairs. This comprehensive study incorporated field learnings, operational successes, and a comparison between the flow test observations and field observations. Finite element analysis and specialized drilling mud contributed to liner installation success for the Hangingstone Expansion.
Performance Step Change in Shallow Extended Reach Wells in Venezuela Enables Drilling Optimization and Increased Heavy Oil Production
Chamat, Elias (Schlumberger) | Cuadros, Guillermo (Schlumberger) | Trejo, Ely (PDVSA Servicios) | Scrofina, Jose (PetroMiranda) | Cermeno, Elio (PetroMiranda) | Rodriguez, Oscar (PetroMiranda)
Abstract In an operation in the Venezuelan Faja, well placement and rotary steerable systems (RSS) enabled drilling faster, longer, and shallower ERD wells than those that have been drilled with mud motors in the field over last 20 years. The results demonstrate a performance step change in this area. Standard drilling in the Faja includes dogleg severity (DLS) requirements as high as 8°/100 ft and rates of penetration (ROPs) as fast as 2,000 ft/hr; these were perfect conditions for using mud motors to drill build sections and horizontal wells. As drilling in the Faja moved south, reservoirs at true vertical depth (TVD) from 1,200 to 1,600 ft started to be developed. Shallow reservoirs and even higher DLS made it inefficient to drill the long 4,000-ft extended reach sections planned as this requires multiple pipe swaps to redistribute heavy bottomhole assembly (BHA) components and wiper trips to clean the hole to allow weight-on-bit (WOB) transmission to reach the bit. To reduce tortuosity, torque and drag, and stuck-pipe events; to improve hole cleaning, WOB transmission, and ROP; and to drill longer horizontal sections, a point-the-bit RSS was tried for the first time in Junin division. The first RSS well drilled in a shallow horizontal well exceeded all objectives and expectations set. Seven more horizontal sections drilled with the same RSS proved the system was robust enough to break a different drilling record on each well. The current shallow extended reach well (SERW) record in the Faja was drilled with a mud motor to 1,231 ft TVD with 4,404 ft of horizontal section and a TVD versus horizontal stepout ratio of 1:4.4. Advanced drilling engineering, bed boundary mapping LWD technologies, RSS, and improved drilling practices in six horizontal sections enabled drilling to similar ERD ratios, while breaking records for ROP, horizontal section length, and drilling and completion speed at similar TVDs. The performance step change in the Faja accomplished through the use of RSS and novel drilling practices has enabled increasing heavy oil production through drilling longer horizontal sections and through the reduction of mud filtrate and formation damage. The performance increase along with lesser tortuosity and friction factors have allowed drilling longer horizontal sections, saving valuable rig time, producing wells earlier, and running liners to total depth (TD) trouble-free unless stopped by oil production.