Day 3 Thu, October 18, 2018最新文献

{"title":"Hydraulic Fracturing Design to Unlock Light Tight Oil Resources in South Oman","authors":"A. Hadhrami, A. Riyami, Ralf Schulz, A. Moiseenkov, F. Khayrutdinov, Dmitrii Smirnov, Nawal Al Kindi","doi":"10.2118/191388-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191388-18IHFT-MS","url":null,"abstract":"\u0000 Field \"A\" produces from a mixed-wet formation comprising of fine grained silicilite. The field is a sour light tight oil reservoir with permeability range from 0.001 – 0.1 mD, the only way to flow the existing vertical wells is through hydraulic fracs. Historically the wells have been fracced using water based frac fluids, which have caused severe negative consequences related to well integrity and reduced productivity. With a recovery factor of <1% after 15 years of production, the main challenge and objective lies in enhancing productivity and unlocking the huge volumes of this reservoir through optimizing the field development concept, completion, frac design and execution.\u0000 A study was conducted with a recommendation to develop the field by drilling slanted wells with ~10 - 15 frac stages. The frac design in itself is unconventional or hybrid where the targeted frac half length is 5x more than the existing conventional ones. The use of oil based frac fluid instead of water is an opportunity actively pursued to enhance productivity and eliminate issues related to scale and corrosion that in the past have resulted in a loss of production.\u0000 Findings of the study have clearly indicated that developing the field with several slanted multi frac wells is economically attractive; with an increase in Net Present Value (NPV) by ~60% and decrease in Unit Technical Cost(UTC) by ~30% compared to developing the field conventionally with vertical wells.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"134 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131148479","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Conceptual Design and Production Enhancement for Ball-Activated Multi-Stage Fracturing Systems in Deepwater Formations","authors":"S. Baǧci, J. C. Flores, L. Castro","doi":"10.2118/191441-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191441-18IHFT-MS","url":null,"abstract":"\u0000 Multi-Zone, Single-Trip (MZST) completions have significantly reduced the time to complete deep wells with long intervals and have been successfully used in Lower Tertiary formations in deep-water Gulf of Mexico (GOM) projects. MZST completion can be used to create the interface with the reservoir and to deliver stimulation treatments typically limited to up to single-digit zones. Additionally, the minimum spacing allowed by standard MZST completions limits the treated zone length.\u0000 The Lower Tertiary formations encounter high-laminated pay zones, often hydraulically isolated, and with pressure variations across the small spacing length. Therefore, a treatment covering several compartments results in uneven treatment distribution across long intervals. These single-trip systems require a high proppant amount and pressure to complete the sizeable frac-pack jobs required in Lower Tertiary formations. Using ball-activated fracturing sleeves and dedicated fracturing ports, these completion systems allow a larger number of stages over multiple intervals. This method affords more precise placement of stages with reduced spacing down to single-digit feet between zones, a feature that also enables targeting specific pressure characteristics in the reservoir.\u0000 Completion selection and well performance analysis were conducted to design a new completion system for production enhancement from Lower Tertiary formations. Design and selection of the lower completion system focused on multi-stage fracturing and potential sand control options, and their impact on production. The following systems were studied to estimate and predict the initial production rates: Multi-Zone Single-Trip (MZST) completion, Large Bore Multi-Zone (LBMZ) completion system and Ball-Activated Fracturing Completion System (BAFCS).\u0000 This paper describes a high-level workflow developed for completion design and selection, fracture modeling to generate 3D fracture geometry and fracturing pressures, wellbore design including tubing stress and movement analysis for fracturing treatments and production systems analysis to generate vertical lift performance/inflow performance relationships (VLP/IPR), and to estimate the initial production rates and flowing bottomhole pressure for sand-free production.\u0000 The proposed BAFCS used more fracture initiation points (up to 20 stages) in the Lower Tertiary formations when compared to eight individual stages (20 perforation intervals) with MZST and LBMZ completion systems. The more confined fracture geometries were created by using the new proposed multi-stage fracturing system. Predicted BAFCS production rates were higher than those of MZST and LBMZ completion systems. To attain higher production and recovery factors than those achievable with natural depletion, artificial lift options (electrical submersible pumping) were also examined for Lower Tertiary wells.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"115 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116313541","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Correlations Between the Economic Value Added and Reservoir and Frac Properties in the Dutch Hydraulic Fracture Portfolio","authors":"T. Huijskes, R. Godderij, T. Leo","doi":"10.2118/191418-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191418-18IHFT-MS","url":null,"abstract":"\u0000 Since the first frac in 1954, around 250 of the 3000 exploration and production wells in the Netherlands have been hydraulically fractured. This study focusses on about 50 of the more recent fracs, of which sufficient production data, reservoir information and hydraulic fracture properties could be obtained for economic and data analysis.\u0000 For each well, the production history has been analyzed with a commercial rate transient analysis software package. About half of the wells have a pre-frac production history while the other half have been hydraulically fractured immediately after drilling. For wells with pre- and post-frac production data two history matched analytical models were made. Those models were subsequently used to create two production forecasts, to determine the incremental production profile and to calculate the economic value added by each frac. For wells without pre-frac production data the history matched post-frac model was used two create two production forecasts, one with and one without a hydraulic fracture in place.\u0000 The calculated economic values have been combined with reservoir properties (permeability, GIIP, stratigraphy, etc.) and frac data (proppant type, amount of fluid used, amount of proppant pumped, etc.), to form a dataset which was analyzed using a commercial data analysis tool to investigate perceived correlations.\u0000 The results show that practically all analyzed fracs resulted in a production improvement, and most of the fracs resulted in positive economic value added. However, some resulted in an economic grey area (below EUR 5 million incremental discounted cash flow), and one frac even resulted in a negative value.\u0000 Many reasons can be given for the distinction between economic and uneconomic projects. This paper shows that although multiple attributes influence the calculated economic value, some generic observations can be made. There is apparently no correlation between PI improvement, skin or kh and economic value. Remaining GIP is definitely important for economic value, but no generic correlation for reservoir pressure can be made. It was shown that wells often see more connected GIIP after fraccing. The results show that fracs in reservoirs with 80% depletion can still result in very economically beneficial projects, especially if the fracs increase the connected GIIP. Frac properties might very well be important for the determination of the economic value of fractures. However, no clear correlation between economic value and frac half length or proppant size could be found. On the other hand, the results show that larger amounts of (any) proppant pumped seem to lead to higher economic value. Last but not least, a relation between PI improvement and pre-frac skin was found.\u0000 The study presented is the first portfolio analysis of fracced conventional gas wells in The Netherlands. Input and methods have been checked and results have been shared with several experts outside our organization.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116872157","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Utilizing In-Situ Mechanical Rock Properties to Target Landing Zones and Improve Completions in the Permian Basin","authors":"E. L. Scott, A. Hildick, Carrie Glaser, E. Petre","doi":"10.2118/191406-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191406-18IHFT-MS","url":null,"abstract":"\u0000 Optimizing horizontal well placement is often not limited to identifying the most favorable reservoir, but also identifying the ideal target window within that reservoir. In unconventional reservoirs, the ideal target window must have both appropriate reservoir quality and the mechanical rock properties conducive to effective hydraulic fracturing. This paper presents two case studies from the Permian Basin. The first study directly compares wireline logs and core data with drilling vibration analysis. Analyzing drill bit vibrations, one can process mechanical rock property data. This process is called drill bit geomechanics. These high-resolution drill-bit-derived data were first calibrated to wireline and core data, then applied to target future landing zones. The second case study compares drill bit geomechanics data across three neighboring 10,000-ft horizontal wells, all of which landed in the same target zone. Based on the drill bit geomechanics data, the three wells showed notable differences in mechanical rock quality. The operator found the three wells’ production responses also differed.\u0000 High frequency measurements of drilling-induced vibrations were recorded through several producing Permian reservoirs. In the pilot well, the recording tool was run behind a coring assembly to obtain mechanical data at in-situ pressure and temperature. Elastic stress-strain relationships were used to solve for the stiffness coefficients and determine relative values of mechanical properties (i.e., Young's Modulus (YM) and Poisson's Ratio (PR)). The resulting mechanical data were compared directly to core analysis, wireline dipole sonic logs, and wireline image logs.\u0000 In general, the mechanical rock properties derived from drilling vibrations compared well with those from the sonic log and core analysis. One can attribute differences between the datasets to fluid effects and differences in resolution. The drill-bit-derived mechanical properties showed fine-scale changes and thinly-bedded intervals that were not identified by the sonic log. Using sonic measurements to determine in-situ mechanical properties can have non-uniqueness. Analyzing cores also includes challenges of translating exhumed core properties to those of in-situ conditions. Combining the in-situ measurement of mechanical properties from drilling vibrations with the traditional sonic log and core analysis minimized uncertainties. Increased understanding of mechanical properties in the pilot well informed the landing zone target intervals for the horizontal well development plan. Understanding mechanical properties is also critical to effective hydraulic fracture stimulation design and execution. Even within a landing zone, mechanical properties can vary laterally. Measuring and understanding these variations in mechanical properties can improve completions and lead to increased well productivity.\u0000 Gathering drill bit geomechanics data provides a lower cost and lower risk method to acqui","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"82 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128238668","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effective Multistage Hydraulic Fracturing of an Extremely Hot Reservoir: Case History","authors":"Chetana Prakash, Mayur Deshpande, M. Mallick","doi":"10.2118/191450-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191450-18IHFT-MS","url":null,"abstract":"\u0000 Hydraulic fracturing formations at temperatures >375°F is challenging because of the unavailability of suitable fluids with sufficient thermal stability. Applying low thermal-stability fluid for fracturing these formations causes rapid viscosity degradation, leading to high fluid loss and narrow fractures. This paper discusses strategies adopted in successful offshore high-pressure/high-temperature (HP/HT) formation multistage fracturing using lower gel-loading fluid.\u0000 Commercially available gelled fracturing fluids are made using polysaccharides or their derivatives. Glycosidic linkages in polysaccharides begin breaking rapidly at temperatures >375°F, making polysaccharide fluids unsuitable for HP/HT hydraulic fracturing when significant fracture conductivity must be achieved. Strategies were planned to cool down the reservoir and bring the temperature into the polysaccharide fluid thermal-stability range. The reservoir's temperature is approximately 400°F and has a high clay content. Performing fluid/clay mineralogy interaction tests optimized the type and concentration of the clay control additive; performing stability tests on an HP/HT viscometer optimized the crosslinked fluid formulation with low polysaccharide gelling agent concentration. Considering well completion and reservoir complexity, a limited entry technique was used to achieve maximum zonal coverage.\u0000 The polymeric clay control additive performed better than conventional salt in clay inhibition; it did not have a negative effect on fluid thermal stability. Metal-crosslinked fracturing fluid containing 45-lbm/1,000-gal gelling agent was stable for approximately 1.5 hours at 350°F; results were comparable with gel having 50-lbm/1,000-gal gelling agent. The strong metal-crosslink bond provided higher thermal stability to the gel.\u0000 Based on petrophysical log analysis, six zones were identified for hydraulic fracturing treatment; however, during execution two zones were combined, so five treatments were successfully executed on a well with a bottomhole static temperature of 400°F in the Krishna Godavari Basin (eastern coast of India). A total of 1,000,000 lbm of high-strength proppant was placed into the formation using approximately 17,000 bbl of crosslinked gel. The zone was perforated in individual clusters; a limited entry technique was used to help treat the zone. The limited number of perforations resulted in increased pressure differential across perforation clusters, leading to effective diversion and maximum zonal coverage. Each stage was isolated using a bridge plug, and diagnostic pumping was conducted before each main treatment. To gain insight into the actual geometries achieved, data acquired during the treatment were history matched using a full 3D grid-oriented hydraulic fracture simulator and compared to initial simulations.\u0000 Fracturing in extreme high temperature with high pressure poses significant challenges. This paper details successful hydraulic fracturing app","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128961515","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Use of Rate Transient Analysis to Evaluate Hydraulically Fractured Well Performance in A Mature Gas Field","authors":"Basayir Al-Lawati, T. Blasingame","doi":"10.2118/191427-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191427-18IHFT-MS","url":null,"abstract":"\u0000 In this work, we assess the historical well performance for a mature gas condensate field in Oman (the field name is designated as \"BHA,\" where \"BHA\" is a pseudonym). The reservoirs of the BHA field are complex and have low permeabilities which results in substantial uncertainty in reserves estimation, which in turn has resulted in regular modifications of the booked volumes. To confine these booked volumes, we employed two techniques: \"time-rate\" analysis (or Decline Curve Analysis (DCA)) and \"time-rate-pressure\" analysis (or Rate Transient Analysis (RTA)).\u0000 To perform the decline curve analysis work we used Microsoft Excel to match data using both the Modified Hyperbolic (MH) and Power-Law Exponential (PLE) DCA relations. We also used the Kappa Engineering product \"Topaze\" to conduct the Rate Transient Analysis (or RTA) by first estimating reservoir parameters and then performing a simulation history match of both the rate and pressure data. The DCA and RTA models were both used to construct a 30-year forecast and 30-year EUR values were obtained using these forecasts. Finally, we created parametric correlations using estimated reservoir properties from RTA and the matched parameters obtained using the MH and PLE relations for DCA.\u0000 The core purpose of this work was to provide assurance in the booked reserves volumes for these low permeability reservoirs and to obtain correlations of reserves and reservoir property estimates for fields like the BHA field.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122273797","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Mitigating Proppant Flowback through Surface Treatment of Proppant-Laboratory Studies and Field Performance","authors":"Weibing Lu, Bill O’Neil, Kewei Zhang, Chuanzhong Wang, H. Quintero","doi":"10.2118/191438-18IHFT-MS","DOIUrl":"https://doi.org/10.2118/191438-18IHFT-MS","url":null,"abstract":"\u0000 Post stimulation proppant flowback can be a serious problem after the hydraulic fracturing process and can cause a variety of issues like: reduced fracture propping resulting in decreased conductivity and hydrocarbon production;erosion related damage to surface and downhole equipment; and increased costs in dealing with recovered proppant disposal. To address the concerns related to proppant flowback, various technologies, including chemical, mechanical, and engineering design have been employed. A common and long term commercial approach is to apply a resin to the surface of the sand. However, resin coatings can be costly relative to the cost of the sand substrate, often doubling or tripling the cost of the sand substrate to which they are applied. Additionally, resin coated proppants often need to be activated with exposure to temperature and pressure. The requirement for additional chemical activators at lower reservoir temperatures can also add additional cost to the treatment. Furthermore, resin coated sands are typically manufactured near a sand mine and then shipped to remote well locations. This offers another layer of logistical complexity to bringing large volumes of sand to a site or often multiple types of sand and thus can add additional costs. In some cases, on-site or near-site manufacturing of resin coatings is possible, but again at an additional cost. A proppant flowback control measure which is cost-effective and can function over a wide range of reservoir conditions would be advantageous to the hydraulic fracturing process.\u0000 A new technology for proppant flowback control was previously presented where chemically modifying the proppant surface with the proppant consolidation additive (PCA) can induce a strong capillary attraction among proppant grains leading to proppant agglomeration (Lu et al., 2016). This study serves to further examine this sand surface modifying chemical. Additional experimental results will focus on conductivity measurement of surface treated proppant and flow resistance tests of treated proppants relative to untreated proppants at varying conditions. The field performance of more than 50 wells in western Canada in terms of proppant flowback control using thisnewly developed technology will also be presented. A discussion of field application and results in several scenarios will demonstrate the correlation of the laboratory experimental results to actual field performance.\u0000 Compared with untreated either Tier 1 or Tier 2 proppant, the surface treatment of proppant increases flow resistance under all the tested confining pressure, also, noticeable increase of proppant conductivity under high confining pressure was observed, which is an advantage of the surface treatment of proppants. The field performance data show that this newly developed technology gives similar or better results relative to resin coated proppants in terms of proppant flowback control. This technology demonstrates the following advan","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117322189","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Coupling Geomechanical Effects and Reservoir Dynamics for Modeling Rejuvenation in Unconventional Plays","authors":"Riteja Dutta, R. Pinto, J. C. Flores, C. Mcburney, S. Stolyarov","doi":"10.2118/180129-MS","DOIUrl":"https://doi.org/10.2118/180129-MS","url":null,"abstract":"\u0000 An integrated understanding of geomechanical effects, fracture propagation and reservoir dynamics is critical in the efficient and cost-effective application of rejuvenation technologies for unconventional plays. While various reservoir models depicting the hydraulic fracturing process are available in the industry, many tend to be simplified or do not capture the numerous parameters that affect both the initial and restimulation processes. This study takes a further step towards building a more realistic picture of fracturing in unconventional plays. In particular, a workflow is presented to couple the geomechanical effects and reservoir simulation modeling in unconventional plays. The objective is to make use of the learnings from this modeling in the successful application of rejuvenation technology.\u0000 The integrated model is developed using existing horizontal unconventional wells in a US shale play. During the initial phase of hydraulic fracturing, variations in stress occur both during injection and production periods. These stresses affect the growth of the fracture and its consequent fracture geometry. While employing various rejuvenation technologies, the ability to re-stimulate the rock will depend on a combination of factors, two primary ones being stress variation and pore-pressure depletion. These effects are incorporated into the reservoir model. Consequently, the production history-matched reservoir model incorporates pressure-dependent permeability variation as well as capillary pressure to account for varying reservoir dynamics.\u0000 Results from this study highlight the importance of changing stress regimes on fracture geometry and its consequent impact on production. We present a methodology to integrate geomechanical effects into a reservoir simulation model. The study also indicates the importance of treatment fluid volumes pumped at various stages during the refracturing operation.\u0000 Additional benefit of restimulating a well will vary from one well to another. The benefit is realized in terms of cumulative fluid volumes and reservoir contacted. The modeling techniques presented may help in application of such restimulation operations based on its impact on recoverable reserves. In summary, this study shows that a comprehensive understanding of stress changes coupled with reservoir dynamics will help better plan the application of various rejuvenation technologies.","PeriodicalId":397259,"journal":{"name":"Day 3 Thu, October 18, 2018","volume":"88 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2016-05-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125023146","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}