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Collaborating Authors
SPE Thermal Well Integrity and Production Symposium
Data-Driven Decision-Making Strategy for Thermal Well Completion
Izadi, Hossein (University of Alberta) | Roostaei, Morteza (Variperm Energy Services) | Mahmoudi, Mahdi (Variperm Energy Services) | Rosi, Giuseppe (University of Calgary) | Stevenson, Jesse (Variperm Energy Services) | Tuttle, Aubrey (Variperm Energy Services) | Sutton, Colby (Variperm Energy Services) | Mirzavand, Rashid (University of Alberta) | Leung, Juliana Y. (University of Alberta) | Fattahpour, Vahidoddin (Variperm Energy Services)
Abstract Various wellbore completion strategies have been developed for thermal wells in Western Canada. The idea in this paper is estimating the improvement of oil production and steam injection if flow control devices (FCDs) will be installed for the next wells to be drilled, or if FCDs were installed at a particular well-pad that has not yet been completed with any FCDs. The approach is based on labeled real data for 68 well-pads from seven major thermal projects in Western Canada. Three phases make up the paper's methodology. The first phase compares wells with and without FCDs to evaluate the performance of the FCDs based on normalized oil production and cumulative steam oil ratio (cSOR). The second phase involves clustering well-pads using an unsupervised incremental-dynamic algorithm. An estimation of FCD contribution to enhancing oil production and cSOR is also performed for test well-pads based on their most similar cluster. In the third phase, cross-validation is employed to ensure that the estimation is trustworthy, and that the procedure is generalizable. To evaluate the performance of FCDs, a reliable comparison was made using normalized oil production and cSOR. Based on our analysis from October 2002 to March 2022, successful FCD deployment resulted 42% more normalized oil and a 37% reduction in cSOR. Among these, liner deployed (LD) FCDs increased oil production by 44% while decreasing cSOR by 58%. Although tubing deployed (TD) FCDs are installed in problematic wells, they produced 40% more oil while decreasing cSOR by 21% in successful cases. Successful inflow control devices (ICDs) increased oil production by 40% while lowering cSOR by 45%. Successful outflow control devices (OCDs) increased oil production by 82% while reducing cSOR by 22%. The clustering algorithm separates the database into four clusters that will be utilized in the estimating phase. In the estimation phase, ten well-pads (15% of the database) are presumed to be new well-pads to be drilled (test data). Based on the estimation results, the root mean square errors (RMSEs) for FCDs contribution to enhancing oil production and cSOR for the test well-pads are 12%. Cross-validation was also performed to assess the approach's predictability for new data, to verify that our technique is generalizable. The findings indicate that FCDs might result in lower capital expenditures (CapEx) and greenhouse gas (GHG) emissions intensity for SAGD well-pad developments, allowing them to reduce emissions. The conclusions of this research will aid production engineers in their knowledge of relative production performance. The findings may be used to examine paradigm shifts in the development of heavy oil deposits as technology advances while keeping economic constraints in mind.
Abstract Well integrity was and continues to be a significant priority for many operating companies around the world. A compromise in well integrity may have direct impacts on production sustainability well life and the environment. Well integrity became an important topic in the last decade after a number of the well blow-outs and oil spills around the world. The new electromagnetic time domain tool (EM) which is presented uses transient or Pulsed Eddy Current (PEC) measurements to perform quantitative evaluation of downhole corrosion in four concentric tubulars individually and to inspect a fifth tubular qualitatively. Case studies are presented that compare results of this instrument with industry-standard single-string evaluation tools such as multi-finger calipers. The novel electromagnetic tool which uses transient or PEC technology comprises three sensors which achieve high-resolution of the inner barrier and high radial depth of investigation for up to five barriers. Each sensor induces coaxial rings of eddy currents in multiple concentric tubulars and measures a time-varying response from the outward-diffusing eddy currents. The full transient responses from multiple sensors are then interpreted to obtain individual tubular thickness profiles. Case studies are presented where electrochemical external corrosion has penetrated inward and has affected the inner most barrier by having through holes which are also verified with another high resolution Multifinger caliper tool. Individual thickness measurement is valuable for proactive well integrity management because electrochemical external corrosion which is the primary corrosion mechanism in these wells causes the outermost casing to fail first and then continues to penetrate inwards. Therefore the new electromagnetic instrument enables early diagnosis of the outer tubulars to identify potential weak zones in the completion string while logging through tubing and eliminating the cost of pulling completions for this purpose. The paper covers the basics of corrosion logging tools and the benefits and drawbacks of running various tools and the advantages of combining several together. Also how the tubing completion like packer setting depths can affect the production casing integrity as well as workover operation impact. New case studies with multi-finger calipers support these conclusions.
- North America > United States > Texas (0.29)
- Asia > Middle East (0.29)
- North America > Canada (0.28)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Field Trial of Nitrogen-Assisted Cyclic Steam Stimulation in Post-CHOPS Wells, Case Study in Sudan
Tang, Xueqing (PetroChina International FZE Iraq Branch) | Yu, Chunxu (PetroChina International FZE Iraq Branch) | Bai, Yang (Petro-Energy E&P Co) | Lu, Hui (PetroChina International FZE Iraq Branch) | Mohamed, Mohamed Salaheldin (Petro-Energy E&P Co)
Abstract: This paper presents the key aspects of nitrogen-assisted cyclic steam stimulation field trial at Post-CHOPS wells in FNE field, Sudan. FNE field is a heavy-oil asset with compositional gradient (13.87 to 18.1°API, in-situ viscosity of 226 to 255 cp) in massive unconsolidated sandstones at depths of 1,500 to 1,900 ft, with a permeability of 2 to 9 Darcies and strong bottom-water drive. Initially, cold heavy oil production with sand (CHOPS) was applied to exploit easy oil at upper zones of entire play. When flow rates of CHOPS wells declined to economic limits, or producers were too cool (reservoir temperature 111°F) to pump efficiently, nitrogen-assisted cyclic steam stimulation was to increase reservoir pressure, decrease heavy-oil viscosity, and boost well production. The specific technical points are highlighted below: In-house studies, including viscosity reduction test and numerical simulations, recommended that steam volume (cold-water equivalent) of 11,442 bbl per cycle based on 268 bbl/ft, with 70 to 75% quality, will be injected into the reservoir at rate of 1,260 bbl/d, nitrogen injection volume per cycle is 4.75 MMscf, soak time is for 5 to 7 days to allow the heat and pressure to distribute more uniform through the reservoir, then go to puff process. Pump is set 30-60 ft below the lowermost perforations to maximize fluids production through keeping fluid-level well below bottom perforations. By the end of pumping, bottomhole flowing pressure can declined to 70 psi. Steam and nitrogen injection sequence at updip wells is to inject steam first, followed by nitrogen injection. For downdip wells, nitrogen injection is the first and steam injection comes later to mitigate water influx. Re-completion strategy: squeeze cement into CHOPS producing zones because they contain wormholes, some communicating with aquifer, and perforate the lower pay interval to extract more viscous heavy oil. Failure risk assessment of production casings: pre-tensioning and full cementing of the casing with thermal cement is adopted in CHOPS wells for post-CHOPS thermal operation. Initial flowback flow rate is limited to less than the level of 500 bbl/d to reduce sanding risk and does not unduly de-pressure the formation at initial production. During pumping process, all fluids are exploited up the tubing string and the annulus is vented the flow-line. Pump works at optimal rate to ensure pressure drawdown less than critical drawdown threshold for sanding and water coning. Field data confirmed that this trial is successful, with 2 to 3-fold production gain, relatively low water cut and no sanding issue. This technology is a useful option for post-CHOPS wells in the similar heavy-oil assets.
- Africa > Sudan (0.84)
- North America > Canada > Alberta (0.30)
- North America > United States > Texas (0.28)
- North America > United States > California > San Joaquin Basin > Kern River Field (0.99)
- Africa > Sudan > Muglad Basin (0.99)
- Africa > South Sudan > Unity > Muglad Basin > Fula Basin > Bentiu Formation (0.99)
- Africa > South Sudan > Muglad Basin (0.99)
Laboratory Experiment and Field Application of a Wet Phase Modified Expandable Graphite Steam Plugging Agent in Heavy Oil Reservoir
Zhao, Guang (China University of Petroleum East China - Qingdao Campus, School of Petroleum Engineering) | Dai, Caili (China University of Petroleum East China - Qingdao Campus, School of Petroleum Engineering) | Xu, Bozhao (China University of Petroleum East China - Qingdao Campus, School of Petroleum Engineering) | Zhao, Wenxun (Sinopec Shengli Oilfield) | Ma, Tiantai (Sinopec Shengli Oilfield)
Abstract Wet-phase modified expandable graphite (WMEG) particles have been successfully developed for in-depth steam channeling control in heavy oil reservoirs. WMEG particles can expand 4 to 7 times in a wet-phase environment and form a worm-like structure at steam temperature. The sand-pack flowing experiments demonstrated that WMEG particles have good injection, steam erosion resistance and selective plugging capacity characteristics. By directly plugging and bridge plugging after expansion, WMEG particles can effectively plug steam channels. To better explain the steam plugging mechanism, the energy changes during WMEG particle expansion were also analyzed. The release of gas at different stages is the source of energy for WMEG particle expansion. WMEG particles have been successfully applied to 12 wells of four typical heavy oilfields in China. The results from these applications confirm that the injection of WMEG particles is an effective steam channeling control treatment. The success of these oilfield tests can also serve as a reference for similar steam injection heavy oilfields.
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin > Chunfeng Field (0.99)
- Asia > China > Shandong > Shanjiasi Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- North America > United States > Louisiana > China Field (0.97)
Integrated Optimization of Hybrid Steam-Solvent Injection in Post-CHOPS Reservoirs with Consideration of Wormhole Networks and Foamy Oil Flow
Hou, Senhan (University of Regina) | Gu, Daihong (China University of Petroleum Beijing and University of Regina) | Yang, Shikai (University of Regina) | Yang, Daoyong (University of Regina) | Zhao, Min (University of Regina)
Abstract In this paper, integrated techniques have been developed to optimize performance of the hybrid steam-solvent injection processes in a depleted post-CHOPS reservoir with consideration of wormhole networks and foamy oil flow. With the experimentally determined properties of injected gases and reservoir fluids by performing PVT tests, history matching of the reservoir geological model is completed through the relationship between fluid and sand production profiles and reservoir pressure. Meanwhile, the wormhole network has been inversely determined with the newly developed pressure-gradient-based (PGB) sand failure criterion. Once the history matching is completed, the calibrated reservoir geological model is used to optimize the solvent(s) and CO2 concentrations, provided that thermal energy, injection rates, and flowing bottomhole pressures are chosen as the controlling variables. The genetic algorithm has been modified and used to maximize the objective function of net present value (NPV) while delaying the displacement front as well as extending the reservoir life with optimal oil recovery under various strategies. Depending on the formation pressure and temperature, soaking time is optimized as a function of solvent concentration and fluid properties. Subsequently, considering the wormhole network and foamy oil flow, such a modified algorithm can be used to allocate and optimize the production-injection strategies with the NPV as the objective function.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.73)
- Geology > Geological Subdiscipline (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Challenges Associated with the Acid Gases Production and Capture in Hydrocarbon Reservoirs: A Critical Review of the Venezuelan Cases
Rodriguez, Fernancelys (Independent Consultant) | Llamedo, Maria (PDVSA INTEVEP) | Belhaj, Hadi (Khalifa University of Science and Technology) | Belhaj, Ahmed (University of Calgary)
Abstract Acid gases production, such as hydrogen sulfide and carbon dioxide, from heavy oil reservoirs in Venezuela is generally associated with the application of thermal enhanced oil recovery methods. These undesired gases, especially H2S, can be removed by injecting chemical additives that promote chemical reactions with oxidative or nonoxidative mechanisms in the producing system to generate fewer toxic byproducts. According to the literature, H2S scavengers evaluated in the oil industry are amines, alkaline sodium nitrite, hydrogen peroxide, triazine, among others. To mitigate both H2S and CO2 from a reservoir, some novel proposals are under study to offer alternatives to control them from the reservoir and reduce their production in surface. This article presents a review of the key parameters that play a role in the generation of acid gases, mainly H2S and CO2, in Venezuelan oil reservoirs. The operational field data, the main reactions and mechanisms involved in the process (e.g., aquathermolysis, hydro pyrolysis), and the type of byproducts generated will be reviewed. The results and knowledge gained will assist in identifying the main insights of the process, associating them with other international field cases published in the literature, and establishing perspectives for the evaluation of the most convenient techniques from health, safety, technical and economic points of view. Lab and field results have shown that the application of thermal EOR methods in reservoirs of the main Venezuelan basins promote the generation of acid gases due to physicochemical transformations of sulfur, and/or fluid-rock interactions. Sulfur content in Venezuelan viscous oil reservoirs, together with rock mineralogy (clay type) has a significant impact on H2S production. Reported lab results also indicated that H2S scavengers reduce the amount of sulfur, and the presence of CO2 also affects the H2S removal mechanisms, depending on which type of scavenger is selected (e.g., amines, triazine, etc.). Solubilization, hydrolysis, adsorption, absorption, and complex sequestrant reactions (oxidation, neutralization, regeneration, and precipitations) are the main mechanisms involved in the removal of H2S. The literature reported that the application of triazine liquid scavengers is found to generate monomeric dithiazine byproducts (amorphous polymeric dithiazine) which might cause formation damage or inflict flow assurance issues upstream and downstream. This work presents a state of the art review on H2S generation mechanisms and new technologies for the mitigation of acid gases in Venezuelan reservoirs. It also provides perspectives for the application of the most convenient technologies for the reduction of greenhouse gas emissions (mostly CO2), which is critical to producing hydrocarbons with low environmental impact.
- South America > Venezuela (1.00)
- North America > Canada (1.00)
- Europe (1.00)
- (2 more...)
- Overview (1.00)
- Research Report (0.93)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Lagunillas Field (0.99)
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Ayacucho Block (0.99)
- South America > Venezuela > North Atlantic Ocean > Eastern Venezuela Basin (0.99)
- (33 more...)