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Collaborating Authors
SPE Thermal Well Integrity and Design Symposium
CT Diagnosis of Well Trajectory and Completion Decision Guidance for SAGD Paired Horizontal Wells
Chen, Xun (Drilling and Production Technology Research Institute of Liaohe Oilfield) | Sun, Shouguo (Drilling and Production Technology Research Institute of Liaohe Oilfield) | Tong, Deshui (Drilling and Production Technology Research Institute of Liaohe Oilfield)
Abstract The trajectory control quality is the key technology when using SAGD dual horizontal wells to produce heavy/super heavy oil. The systematic study of trajectory control, CT scanning diagnosis and completion decision has been carried out to guarantee the forming and keeping of steam chamber and enhance the drainage continuity and well-bore life so as to realize economical and effective development. In order to realize precise control of the trajectory of dual horizontal wells, the method with space rectangular target for dual horizontal wells and MGT magnetic-steering technology as its core, has been developed. The CT scanning diagnosis system of SAGD trajectory based on the medical technique has been developed to realize real-time scanning and predicting of the horizontal intervals of the paired horizontal wells. The timely warning and guidance of trajectory adjustment are available when the deviation of the relative position of the two wells from the space rectangular target occurs. After drilling, the space position relation of arbitrary cross-section along the trajectory axis is analyzed through the scanning diagnosis system, and scientific evaluation of the SAGD production is conducted using the SAGD efficiency coefficient method. If the relative position of certain intervals of the two wells is pretty near and there will be the risk of steam breakthrough, physical isolation of the intervals are recommended with casing and thermal packers. The technology has been applied in 12 well-groups in the Liaohe Oilfield, most of the dual horizontal wells have kept favorable position relations. During the injection well of Du-A well-group, due to the large formation dip, the scanning diagnosis system sent out warning signals when 2/3 of the horizontal interval had been drilled, then technicians adjusted the trajectory timely. After drilling, it was found that the distance between the two wells was less than 4m for a 4-meter interval at the 2/3 of the horizontal interval. During the design of completion strings, a blind tube is used to replace the screen in the interval. Two thermally-setting packers are designed respectively for the upper and lower end of the blind tube to realize physical isolation so as to ensure the formation of the steam chamber in the later period and guarantee favorable oil drainage. The overall production of the block has been increased by 15% compared to the wells in the earlier stage. After study, the SAGD trajectory control and completion decision technology with integral constraints of the space rectangular target, real time control of CT scanning diagnosis system and decision guidance after completion has been developed to successfully remove the potential developing troubles caused by trajectory control quality. With favorable applications in the field, the technology has become an important method to guarantee SAGD development effects.
- North America > Canada (0.29)
- Asia > China > Liaoning Province (0.25)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.35)
- Geology > Geological Subdiscipline (0.35)
Abstract Steam circulation in the early stages of Steam-Assisted Gravity Drainage (SAGD) is crucial for establishing hydraulic communication between the injector and producer well and for the future development of the steam chamber. Steam is the carrier of enthalpy to the reservoir, and thus, the evolution of pressure, temperature, and steam quality is important for heat transfer efficiency. In the simulation of the circulation phase (start-up), most companies in Alberta neglect the heat loss around the wellbore in the vertical/build section of the well and assume a steam quality for the lateral section of the well. Also, most of the simulations found in the literature assume a source-sink approach where the frictional pressure drops along the wellbore and the heat conduction between the wellbore and the reservoir are negligible. In this paper, the steam circulation phase of a SAGD well pair is examined in detail, taking into account heat loss around the wellbore in the vertical/build section and heat transfer and fluid losses in the lateral section of the well pair. In the model developed, wellbore hydraulics is also accounted for by using a discretized wellbore model within a fully implicit coupled thermal reservoir simulator. Field data from the circulation phase or warm up phase of a SAGD well pair at the Lindbergh SAGD project was history-matched to better understand the effect of wellbore hydraulics and heat loss between the dual completion string design and wellbore. This research will help Pengrowth Energy Corporation take into account new operating strategies for future SAGD well pairs.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.49)
- Geology > Geological Subdiscipline (0.35)
Abstract Flow Control Devices (FCDs) in SAGD applications have succeeded and failed to varying degrees and their use has not been overly pervasive or fully accepted yet. However, recently it has been publicized that FCD technology has achieved upwards of 100% improvement in SAGD oil production and potential improvements in steam oil ratios (SOR), which has continued to spark interest in its application. SAGD reservoirs are inherently heterogeneous and this presents distinct operational complexities when attempting to expedite the production of the oil while attempting to avoid steam breakthrough. Producing the steam reduces the thermal efficiency of the project which results in an increased SOR while also creating a high potential of compromising the mechanical integrity of the production liner. FCDs can mitigate the operational negatives and enhance the operational positives, however, they are not a ‘silver bullet’ for all ailments and their implementation needs to be carefully planned. This paper reviews FCD implementation workflows and highlights recent downhole instrumentation technology advancements that enhance FCD performance analysis and supports better deployment designs that should improve the economic viability of existing and upcoming SAGD projects.
- North America > United States (1.00)
- North America > Canada > Alberta (0.95)
- Europe (0.68)
- Asia (0.68)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Surmont Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- (10 more...)
Abstract Thermal recovery is becoming a main stream enhanced recovery method for heavy oil with unique challenges. The extreme nature of thermal recovery requires flexible and creative approach to address the unique challenges. One of the accepted recovery thermal methods is Cyclic Steam Stimulation (CSS). The thermal cycle starts with injection phase followed by soaking, and finally, production phase. Conversion from injection phase to production phase is considered a significant operational risk in addition to typical risks associated with oil production operations. The additional risk during the conversion to production from an injection cycle is due to the significant energy placement in the reservoir during steaming. If not controlled, high energy hydrocarbon fluids flowing back to surface can lead to loss of containment and harm to life or the environment. Beam Pumps have been used predominantly in conjunction with insert down-hole pump and sucker rods. During injection phase, the well is operated as an injector without pumps or rods, and when the time comes to convert to a producer, rods and insert pumps are reinstalled. This conversion step from injector to producer is highest risk in the CSS well operation cycle. After the injection cycle is completed, a significant energy is placed into the reservoir, the well is shut in for soaking period which is 1-3 days. Free flow is required after the shut in period to depressurize the well. Depressurization period extends in some cases to many weeks and would require killing the well where it's common that a well would not die off just by depressurization alone resulting in significant wait time. The amount of flow back and energy stored in the well is directly proportional to steam injection pressure and duration. In many cases where well still retain some energy and pressure is still high for intervention, due to free flowing not subsiding, killing the well is utilized. Well killing procedures pose another set of challenges such as; pump start up challenges due to viscosity reduction, cost for brine mix and wrong pressure estimation leading to prolong interventions. The challenges in CSS opened an opportunity for innovation where thermal wells could be attended for conversion with minimum rods taken out or rods added back in under high temperature and pressure. The new concept is a combination of dual rod Blow Out Preventer (BOP) and stripper seals set in series. A trial in November 2017 was conducted with positive results where the advantages of this innovation were clearly demonstrated. This paper is a summary of the design approach and the successful trial proving the concept.
Standalone Sand Control Failure: The Role of Wellbore and Near Wellbore Hydro-Thermo-Chemical Phenomenon on the Plugging and the Flow Performance Impairments of the Standalone Sand Screen
Mahmoudi, Mahdi (RGL Reservoir Management) | Roostaei, Morteza (RGL Reservoir Management) | Fattahpour, Vahidoddin (RGL Reservoir Management) | Uzcatequi, Alberto (RGL Reservoir Management) | Cyre, Jeff (RGL Reservoir Management) | Sutton, Colby (RGL Reservoir Management) | Fermaniuk, Brent (RGL Reservoir Management)
Abstract Although several workflows have been developed over the years for the design of the optimal sand control solutions in thermal applications, numerous sand control failures still occur every year. This paper aims at assessing the failure mechanism of different sand control techniques and the factors contributing to the failure by analyzing different failed sand control screen samples recovered from thermal and non-thermal wells. Several failed standalone screens have been studied, which were collected from various fields and operational conditions. The screens were first inspected visually, and then certain sections of screens/pipes were selected for more detailed study on the failure mechanism. The liners/screens were cut into sections to be studied through SEM-EDX, reflective light microscopy, X-ray micro CT scan and petrographic thin sections to better understand the localized plugging mechanism. Through the studies of several polished sections, a statistical variation of the plugging zone was found. Moreover, we further focused on the critical zones such as the inlet and outlet of the aperture and the zone adjacent to the formation to better investigate the plugging mechanism. The study on wire wrap screen samples revealed significant plugging of the annular space between the base pipe and the screen. Extensive clay/fines buildup in the annular space led to full to partial clogging in some sections. The base pipe corrosion study reveals that the corrosion mechanism is highly flow dependent since the perforation on the base pipe was enlarged to an oval shape from the original circular shape with its larger axis pointing toward the flow direction. The size of the plugged zone was significantly higher in the outer diameter section where a mixture of the clay and corrosion byproducts plugged the near screen pore space and the screen aperture. Examined premium mesh screen samples showed that the plugging mechanism is highly sensitive to the mesh size and assembly process. The highest pore impairments were associated with mesh screens in which the mesh was directly wrapped around the base pipe causing a reduced annular gap for the flow toward the perforations. The investigation of slotted liner samples showed widest plugging zone in the slot entrance and the lowest on the slot wall. A distinct interplay of the clay and corrosion byproduct led to the adsorption of clay, forming a compacted layer over the slot wall. This paper reviews the plugging mechanism of the standalone sand control screen obtained from the field to provide first-hand evidence of the plugging mechanism and provides explanations for some of the poor field performances. The results could help engineers to better understand the micro-scale mechanisms leading to sand control plugging.
- North America > United States (1.00)
- Europe (1.00)
- North America > Canada > Alberta (0.95)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- North America > Canada > Alberta > Whitelaw Field > Acl Whitelaw 6-29-81-1 Well (0.93)
Visualization of Fines Migration in the Flow Entering Apertures through the Near-Wellbore Porous Media
Ansari, Shadi (University of Alberta) | Yusuf, Yishak (University of Alberta) | Kinsale, Lisa (University of Alberta) | Sabbagh, Reza (University of Alberta) | Nobes, David S. (University of Alberta)
Abstract Various slotted liners geometries are used to control the sand production in SAGD operations. The geometry of a slot (shape and size) not only affect sand production but it may also influence fine deposition and scaling at the slot entrance. Failure of SAGD wells due to the deposition of particles is an important issue that needs to be investigated at the pore scale. This study provides a fundamental understanding of fines transport and the plugging potential at the entrance of the slots on slotted liners. Three slot profiles including straight shape, keystone shape and seamed (rolled top) shape are examined experimentally in relation to the preceding conditions of pore spaces in porous media. The potential of slot plugging is also studied from the fluid flow motion perspective. This task is achieved by visualization of the flow passing through the near well bore region of different slot geometries using an optical technique, namely, particle image velocimetry. Motion of small particles (D = 20μm) in the oil flow are captured before entering the slot, at the entrance and after leaving the slot entrance. The changes in the streamlines and velocities are analyzed to estimate the potential plugging locations. The results highlights how changing the entrance geometry of the slots may increase the deposition potential in and around a slot. The flow of the oil within the near wellbore porous media have also indicated that depending on the locations of the porous media within the flow structure, different deposition pattern may take place. Based on the result of this study it can be concluded that among the slots, keystone has the highest potential for the particle build up within and at the entrance of the slot.
Abstract Although thermal heavy oil recovery methods are extensively used, no unified and standardized basis exists for selecting materials and configuring intermediate (production) casing/connection systems for these extreme-service applications. Thermal intermediate casing systems must accommodate a wide variety of mechanical and environmental loads sustained during well construction, thermal service at temperatures exceeding 200°C, and well abandonment. Numerous operator- and field-specific designs have been used with good success and only a few isolated challenges, but industry's use of its operating experience to calibrate tubular design bases for future wells has been limited. This paper identifies the benefits and components of a unified casing system design basis for thermal wells, aimed to be technically comprehensive, inclusive of the available elements of industry's collective knowledge and experience, and adaptable to technological advancements. The technical element of the unified basis broadly relates to the engineering foundation used to make three primary design selections: material, pipe body, and connections. For each design selection, the paper provides an overview of the associated technological challenges and the current state of the industry in addressing those challenges, including the commonly-adopted design approaches. Key performance considerations include integrity during well construction, connection thermal service structural integrity, pipe thermal service integrity and deformation tolerance, connection sealability, and casing system environmental cracking resistance. Where applicable, the paper identifies interdependencies that exist between design selections (for instance, the impact of pipe material selection on the thermally-induced axial load that must be borne by the tubular and connection), and discusses mechanisms for accounting for those added complexities in the design. Ultimately, the intent of this paper is to provide a framework for referencing existing technical knowledge and for considering further development and field benchmarking work that will reduce the technological uncertainty and increase simplicity in thermal casing system designs. Industry will benefit from a unified engineering approach that offers operators sufficient flexibility to accommodate application requirements and prior experience.
- Europe (1.00)
- Asia > Middle East (0.92)
- North America > Canada > Alberta (0.69)
- (2 more...)
Abstract This paper describes a novel approach in drilling production wells while implementing real-time mapping of the Bitumen-Water Contact (BWC) with extra-deep azimuthal resistivity (EDAR) logging while drilling (LWD) service, thereby resulting in an increase of exploited bitumen reserves by optimizing wellbore placement. Within the Athabasca Bitumen Reservoir, the EDAR LWD service confidently mapped the BWC within a range of 2-22 meters below the entire producer wellbore. It also provided an earlier warning of an approaching low resistivity boundary, which allowed the operator to optimize the wellbore placement using real-time proactive steering decisions. In contrast to the existing azimuthal resistivity tools, which have the limited depth of investigation, this approach significantly mitigated the risks of intersecting or giving an incomplete picture of BWC surface. The real-time interpretation of extra-deep azimuthal resistivity data provided better understanding of the lateral distribution of the McMurray Formation along the horizontal wellbore, lithologically varying from clean sand facies to mud-filled channel facies and inclined heterolithic stratification (IHS) facies. The fluid heterogeneity of the reservoir included partial reservoir charging, irregular BWC and lean zones, which compounded lithology complexity within the reservoir. In one of the case studies, 50 percent increase was achieved in actual exploited bitumen reserves in comparison to the projected exploited reserves if drilled per the planned trajectory. This new LWD approach was proven effective while drilling horizontal appraisal and producing wells in unconsolidated formations with high reservoir heterogeneity, it offered an opportunity to better understand the bitumen reservoir and ultimately led to increased production performance of Oil Sands projects.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.61)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract The operator experienced an unusual casing failure at a producing SAGD (steam assisted gravity drainage) oil well in summer of 2017. The subject well in the Firebag SAGD field of NE Alberta, Canada had operated successfully for over 11 years. Once the problem was identified, the well was shut in to determine the nature of the failure and options for repair and recovery so it could be returned to operation as soon as possible. Tasks included identifying and isolating the failure, establishing the cause and nature of the failure, and determining viable repair options. Logging diagnostics to measure/image the failure were performed, which included new ultra-sonic logging imaging technology, high-resolution multi-finger caliper logging, a downhole camera run and conventional eddy flux casing inspection log. Historical log data was also reviewed to assess whether the failure evolved over time, or if the mechanism was acute. Once the nature of the failure was established, the optimal repair method was chosen, planned and carried out. Sophisticated analysis of multi-finger caliper log data, camera images and new technology in the form of an ultrasonic imaging tool for the casing were utilized and are presented. A discussion of potential root cause mechanisms for thermal wells is provided, including a variety of failure modes that could be ruled out. Confidence in the failure mode specific to this well was increased by considering information acquired from multiple diagnostic tools. The nature of the connection failure determined from this process is outlined, along the rationale behind the repair method selected to remediate the well.
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Firebag Oil Sands Project > Wabiskaw-McMurray Formation (0.99)
Abstract Part 1 of this study (SPE-187956-PA) presented a method to calculate the liquid pool level from temperature profile in observation wells, provided new insight into how factors like wellbore drawdown can compromise subcool control and cause steam breakthrough, and illustrated how liquid pool depletion may result in uncontrolled steam coning with time. In Part 1, the algebraic equation for liquid pool depletion based on wellbore drawdown, subcool and emulsion productivity was generated. However, not included in Part 1 was an examination of the effect of localized hot spots on well control, which is the focus of this paper. As a part of this study, the effect of localized hot spots is mathematically included as a virtual skin factor representing the hot spot length in the algebraic equation for liquid pool depletion. The results of this work suggest that longer hot-spot will yield to lower differential pressure and make it harder to control the steam breakthrough by choking the well at a given rate. Two important finding of this work are that: (1) the zero-differential pressure (or steam coning) in reservoirs with higher permeabilities occurs in shorter hot-spots; and (2) it is harder to control the steam coning in high permeability reservoirs after hot-spots develop. Flow control devices (FCDs) have been extensively used in horizontal wells for conventional oil and gas production in order to prevent early water break-through or gas coning. The benefits associated with this technology in SAGD industry have been studied with reservoir simulations and validated with field experience. The cost comparisons of bridge plug at the toe and scab-liners in heel with FCD installation along the producer is typically not large, which makes the FCDs the more attractive full life cycle option in producers experiencing hot-spots. Although installation of FCDs to prevent steam coning after steam breakthrough and hot-spots creation is part of the common practice as retrofits by SAGD operators, in recent years FCDs are now often installed to improve SAGD well pair performance as part of the initial completion. Although FCDs have demonstrated potential for improving recovery in SAGD production wells, vendors use a variety of approaches when designing their FCDs independent of the liquid pool element resulting in many cases where the field results showed no improvement. It is necessary to accurately characterize different FCDs under different reservoir conditions. In this study, the liner deployed FCD and liquid pool systems are coupled, and two criteria are suggested as for a design of liner deployed FCDs on the basis of pressure drop ratio of FCD relative to the liquid pool (ΔPFCD / ΔPpool) and the coefficient of variation (CoV) of inflow for the liner deployed FCD wellbore (CoVFCD).