Day 3 Wed, June 27, 2018最新文献

{"title":"The Faults in our Fields – Well Count and Placement in a Columbus Basin Gas Field","authors":"Joel Dowlath, K. Onyeagoro, Elizabeth Sookal, Kevan Quammie, Ashwin Srinivasan","doi":"10.2118/191226-MS","DOIUrl":"https://doi.org/10.2118/191226-MS","url":null,"abstract":"\u0000 The Enterprise gas field is a discovery in Shell's operated acreage in the Columbus Basin off the east coast of Trinidad. It is comprised of two major fault blocks, with an exploration well in the smaller one and an appraisal well in the larger one. The larger fault block is further broken up by minor faults. The potential compartmentalization of this fault block is the major uncertainty in the development of the Enterprise field.\u0000 The development plan called for one or two wells to be drilled in the Enterprise field. Detailed mapping of each of the minor faults and analysis of log and pressure data from the wells was used to determine how well connected the various segments are. Using relationships derived from a global database and Vshale logs from offset wells, a range of fault transmissibility multipliers was derived for each fault based on calculated shale gouge ratios and mapped fault throws.\u0000 Results of the dynamic fault seal analysis were integrated with dynamic simulation and showed that using base case fault transmissibility multipliers, for all segments where there is reservoir-reservoir juxtaposition across the minor faults, there will be connectivity and the larger fault block can be drained by a single development well. Various combinations of well placements were tested against low, base and high case geological realizations and these were used to determine the optimal development scenario for the field.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"98 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77030874","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":"A Study in Quantifying Thin-Bedded Pay Contribution Within a Deltaic System in the Columbus Basin","authors":"J. Fortune, R. Jackman","doi":"10.2118/191231-MS","DOIUrl":"https://doi.org/10.2118/191231-MS","url":null,"abstract":"\u0000 The objective of this study was to systematically and quantitatively quantify where production from Thin – Bedded Pay may be more challenging using conventional methods of completion. This study will focus on different areas within the deltaic environment in which Thin – Bedded Pay are prominent. A 3D structural model was built and populated with properties to represent four (4) different main classes of geological environments with a deltaic system. It explored the effect of completing across the conventional sands only vs completing both the conventional and secondary units. The main finding in this thesis is that completing the thin-bedded pay increased the overall rate of the production on average of about 10% in different environments. In addition, in complicated reservoir architecture environments such as the upper slope and distal delta slope environments, there are significant (14% and 10%) incremental increases in the recovery factors by completing across these thinly bedded zones. Thus, it is recommended that these environments be further explored in how best to develop the thin-bedded resource in these environments since, in a time when the finite resources of oil and gas are becoming scarce, it is important to understand what reserves we may have that are not currently being tapped into.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84063583","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":"Application of Integrated Dynamic Asset Modeling to Predict and Resolve Production Instabilities in an Offshore Facility, A Case Study, Mexico","authors":"O. Espinola, R. Mehranfar, J. Álvarez, J. Villanueva, L. Vazquez","doi":"10.2118/191270-MS","DOIUrl":"https://doi.org/10.2118/191270-MS","url":null,"abstract":"\u0000 Integrated asset modeling has been used for the last decade with a wide technical application covering different challenges from field development to production optimization. Besides supporting the FEEDS and FEL studies for different purposes. Moreover, the technology has evolved in terms of integration and dynamic or transient simulation has been added as an extra element expanding the possibility to cover different challenges and workflows. The objective of this paper is to show how this dynamic integration (Dynamic integrated asset modeling) was applied to a common problem of several reservoirs that produce water and gas under different dynamic mechanisms (injection, aquifer and gas cap) to understand, from the reservoir perspective, the effects of gas and water conning over the entire production system.\u0000 The methodology applied was using a refined sector model solved with numerical simulation and coupled with a transient multiphase flow simulator to see how pressure drop affect the contacts level and shape based on the petrophysical properties and under different production scenarios and generate different graphics to see how this phenomenon behaves. Besides a comparison with all the most analytical correlations used in the literature to identify gas and water conning was performed to see the differences among them and with this dynamic integrated approach. On the other hand, for the production side this coupled model was applied to an offshore facility to see these reservoir effects in the transport system and how they impact in the pipeline and riser due to this abrupt entrance of gas and water changing the flow conditions, flow patterns, pressure drop and creating some instabilities in the separators caused by severe slugging.\u0000 The results of this analysis were very useful to understand the total production systems (reservoir-surface) behavior, predict the gas and water breakthrough, establish the critical rates to avoid these problems and see how the results differ in some cases with the common analytical correlations. Specific conditions in the pipeline and riser were established to quantify the slugging problems and evaluate different alternatives to eliminate the instabilities through proposing different scenarios such as gas injection in the riser, top side choking, etc. Application of this integrated approach has been very beneficial in recognizing the source of the problem, offer proper and feasible solutions in development and operational phases. In addition, validating and reducing uncertainty of related literature correlations and give to the production and reservoir engineers a quick and reliable way to know the critical rates that can support the decision-making process.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73763748","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":"Bond Log Analysis Offshore Trinidad","authors":"C. Welsh","doi":"10.2118/191207-MS","DOIUrl":"https://doi.org/10.2118/191207-MS","url":null,"abstract":"\u0000 This paper analyses the results of the combined Cement Bond Log/ Variable Density Log /Radial Bond Log (CBL/VDL/RBL) tool run on 10 consecutively drilled offshore development wells by an operator during the 2015/2016 period in Trinidad and Tobago. The Bond Index (BI) is used as a quantitative criterion for measuring cement to casing bond and the VDL/RBL as a qualitative criterion for cement to formation bond. The performance of the wells after perforation is examined with the aim of highlighting the importance of a good cement job for successful production. Cement pump pressure/pump rate/cement density charts are also examined to explain cement job outcomes.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82075031","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":"Water Performance in Toe-Point Injection Wellbores at Supercritical State","authors":"Fengrui Sun, Yuedong Yao, Guozhen Li, L. Zhao, Hao Liu, Xiangfang Li","doi":"10.2118/191151-MS","DOIUrl":"https://doi.org/10.2118/191151-MS","url":null,"abstract":"\u0000 Most of the previous works were focused on the saturated/superheated steam flow in wellbores coupled with conventional single-tubing injection method. With the rapid development of technology. Supercritical water coupled with toe-point injection technique is proposed.\u0000 Compared with conventional method, supercritical water could heat the reservoir to a higher temperature, obtain a larger heated radius, and obtain a higher thermal cracking efficiency etc. Besides, toe-point alternating heel-point injection could release the phenomenon of unequal absorption of steam when the horizontal wellbore is extremely long or the reservoir is of serious heterogeneity.\u0000 This paper presents a model for estimating thermal properties of supercritical water along the inner tubing (IT) and annuli in the horizontal section of the wellbores with toe-point injection technique. Firstly, a flow model in wellbores is proposed based on the mass, energy and momentum conservation equations. Secondly, coupled with flow model in reservoir, a comprehensive mathematical model is proposed. Thirdly, type curves of supercritical water flow in horizontal wellbores with toe-point injection technique is obtained by finite difference method on space and iteration technique. Finally, sensitivity analysis is conducted.\u0000 Results show that: (a) supercritical water temperature decreases rapidly from heel-point to toe-point in IT. The temperature decrease rate near toe-point of wellbores becomes smaller. (b) The larger the pressure difference, the larger the mass injection rate from annuli to oil layer. (c) When the mass injection rate is small, heat loss from fluid to reservoir plays an important role on temperature drop. (d) When the injection rate is high enough, the effect of heat loss on temperature drop becomes weak. (e) The pressure of supercritical water at a certain place in IT or annuli decreases with injection rate.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85354669","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":"Re-Evaluating Contributions from Thin Bedded Reservoirs: Integrated Reservoir Modelling of the Greater Dolphin Area","authors":"D. Ryan, Nwenna Crooks-Smith, P. Nurafza, Candice Ogiste, S. Calvert","doi":"10.2118/191166-MS","DOIUrl":"https://doi.org/10.2118/191166-MS","url":null,"abstract":"\u0000 The Dolphin Field has been producing gas since 1996, however predicting in place volumes, reserves and forecasting production has been a challenge since field inception. The fact that in place estimates have increased significantly since development sanction highlights that a range of geophysical, geological and petrophysical uncertainties are associated with the field. Historically, static volumes have been smaller than dynamic volumes estimated from material balance. The explanation of this difference traditionally related to uncertainty in contact depth (given the minimal data on contacts), that adversely caused poor predictions of water production in the historical models.\u0000 Many of the reservoir units within the Greater Dolphin Area (GDA) are characterised by a heterolithic deltaic succession of centimeter scale very-fine sandstone, siltstone and mudstone. Given the thin-bedded nature of the reservoir, conventional wireline-logging tools lack the resolution to accurately resolve many of the static parameters including water saturation. However, based on the available PLT data, it is believed that these thin-bedded intervals generally contribute to the production from the wells and hence to the fluid flow in the reservoir.\u0000 A new static and dynamic reservoir model of the GDA has been built that integrates and incorporates new seismic interpretation, petrophysical recharacterization, revised geological and reservoir engineering concepts, and eventually history matching to production data. A key component of this new model build has been integrated modelling iterations amongst different disciplines from new petrophysical interpretations through to dynamic simulation. Initial iterations used a conventional formation evaluation method and resulted in simulations that showed accelerated pressure drops (compared to production data) as a result of failure to capture flow from thin-beded intervals. An alternative petrophysical methodology that aims to better estimate water saturation within thin bedded intervals has been incorporated into a new workflow to account for the thin bed volumes. The new thin bed simulation model results in greater gas contributions from the thin-bedded intervals and helps overcome the historical shortage of static volumes required to achieve a pressure match.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"61 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75292335","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":"Engineered Wellbore Strengthening Application Enables Successful Drilling of Challenging Wells","authors":"Godwin Chimara, A. Calder, W. Amer, Philip Leslie","doi":"10.2118/191219-MS","DOIUrl":"https://doi.org/10.2118/191219-MS","url":null,"abstract":"\u0000 Four wells were successfully drilled and completed, but high drilling fluid densities (1.95 to 1.98 SG) were necessary to maintain wellbore stability in the overburden section immediately above the depleted reservoir. The estimated hydrostatic overbalance from the drilling fluid was approximately 800 bar (11,603 psi) higher than reservoir pressure. A wellbore strengthening technique was selected to seal the calculated 1500 μm fractures induced by these high pressures. This paper highlights the engineering, logistical, and operational challenges encountered while successfully drilling and completing such wells.\u0000 Geomechanical data was initially acquired, including Young's modulus, Poisson's ratio, and minimum in-situ horizontal stress; and, together with the operational parameters [hole diameter and equivalent circulating density (ECD)], these data were used to estimate fracture width (1500 μm). Subsequently, a drilling fluid system was engineered and customized to seal such fractures, thereby strengthening the wellbore to help minimize losses in the reservoir. The solution was validated at two separate laboratories. Large particulate materials with a D50 of 600 to 2300 μm were used. Improvement opportunities during execution were captured for the next cycle.\u0000 A total drilling fluid loss of 512 m3 during a 16-hour period was experienced in one well after a drilling liner packoff occurred, and fractures greater than 1500 μm were initiated; however, the liner was successfully cemented in place. The coarse particulate materials (600 to 2300 μm) were mobilized in 500 and 1000 kg bags to minimize deck space requirements on the rig and help facilitate ease of mixing. Rig mixing and pit agitation capacity were important for effective mixing of the fluid system. The application also provided the opportunity to align testing procedures and equipment between the field and laboratory. With increasing reservoir depletion, the potential exists for fracture width increases that can impact the particle size of materials necessary to effectively design a solution. Engineered particulate solutions provided a pathway for sourcing and procuring the necessary wellbore strengthening materials.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81574188","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":"Integrity Failure of Cement Sheath Owing to Hydraulic Fracturing and Casing Off-Center in Horizontal Shale Gas Wells","authors":"Kui Liu, D. Gao, A. D. Taleghani","doi":"10.2118/191196-MS","DOIUrl":"https://doi.org/10.2118/191196-MS","url":null,"abstract":"\u0000 The sustained casing pressure (SCP) in shale gas wells caused by cement sheath failure can have serious impacts on safe and efficient gas production. Although horizontal wells are widely used for production from Shales, the cementing quality and casing centericity is barely ensured. Among other indications, the casing off-center is iedtified very often in the wells with SCP problem in Sichuan field. Hence, the objective of this study is to analyze the effect of the casing off-center on the integrity of the cement sheath. To better understand stress distribution in eccentric cement sheaths, an analytical model is proposed in this paper. By comparing the results of this model with the centeric casing, the impacts of casing off-center on integrity of the cement sheath is analyzed. During the fracturing treatment, the casing off-center has little effect on stress in the cement sheath if the well is well cemented and bonded to the formation rock. But on the contrary, the casing off-center has serious effects on stress distribution if the cementing is done poorly. The debonding of casing-cement-formation interfaces can significantly increase the circumferential stress at the cement sheath. At the narrow side of the cement sheath, the circumferential stress could be 2.5 times higher than the thick side. The offset magnitude of the casing eccentricity has little effect on the radial stress in the cement sheath but it can significantly increase the shear stress. We found that the risk of cement failure may reduce by making casing string more centralized, increasing the thickness of casing. The results provide insights for design practices led to better integrity in shale gas wells.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"74 11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91029506","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":"Application of Blasingame Type Curves to a Multi-Well Gas-Condensate Reservoir: Field Case Study","authors":"P. M. Adrian, M. Cabrera","doi":"10.2118/191214-MS","DOIUrl":"https://doi.org/10.2118/191214-MS","url":null,"abstract":"\u0000 Nowadays advanced decline curve analysis techniques are widely accepted for estimating Hydrocarbon Initially in place (HCIIP), reservoir parameters and production forecasting. These analytical techniques were developed assuming different reservoir models and wellbore geometries. Most of them considered an ideal single well reservoir system, which is not a common scenario of production.\u0000 In light of that, some authors have proposed theoretical solutions for the analysis of production data of multi-well reservoir. Gas and oil reservoirs has been studied and validated with reservoir simulation models; however the application to real field case was not addresses in detail. There is an example for gas-condensate reservoir with the multi-well approach and the other for an oil field by applying a single well methodology.\u0000 This paper presents a field case study application of Blasingame type curve method to a multi-well gas-condensate reservoir. Total material balance pseudo-time was calculated using the two-phase compressibility factor. Bottomhole flowing pressures were calculated with vertical flow correlations and adjusted with dynamic gradients. A single well production data was analyzed to estimate the total Original Gas In-Place of a gas-condensate reservoir as well as reservoir parameters.\u0000 The results of the multi-well method were comparable with volumetric and conventional material balance estimations, as well as well testing interpretation results. Therefore the reliability of the multi-well type curve approach to gas-condensate reservoirs was confirmed.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"7 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91508436","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":"High Efficient Imbibition Fracturing for Tight Oil Reservoir","authors":"Chunpeng Wang, Weixiang Cui, He-wen Zhang, Xiaohui Qiu, Yuting Liu","doi":"10.2118/191274-MS","DOIUrl":"https://doi.org/10.2118/191274-MS","url":null,"abstract":"\u0000 In view of tight oil reservoirs with no natural productivity (tight sandstone and carbonate reservoirs with matrix permeability under overburden pressure of no more than 0.2mD (pore permeability less than 2mD)), a nanometer high efficient oil washing agent has been developed by combining nano-drop, high efficient oil washing surfactant and wettability reversal means, which can turn the disadvantage of the small pores and throats into advantage and realize fracturing effect enhancement by making use of the spontaneous imbibition.\u0000 For the tight oil reservoir, large scale and high pumping rate multi-stage fracturing in horizontal wells and fracture diversion technique are recommended to smash the reservoirto create a fracture network of natural fractures and artificial fractures for oil and gas flow. The aim is to increase reservoir stimulation volume and the artificial fracture area. Meanwhile, nanometer high efficient oil washing agent is added in the fracturing fluid. By changing rock wettability, the oil-wet interface is turned water-wet, and the capillary force is changed from imbibition resistance to imbibition drive, boosting spontaneous imbibition. Therefore, the biobased solvent and surfactant can work in synergy to separate the oil film from pore and throat surface, realizing displacement of oil by water. Experimental data shows the application the nanometer oil displacement agent can enhance the oil displacement efficiency of core by12%. After fracturing, the well should be shut down for some time. The shut-down time should take the reservoir pressure and temperature, pore structure and connectivity and the imbibition capacity of the fracturing fluid etc into account, and can be worked out by spontaneous imbibition experiment and NMR etc to guide field operation.\u0000 This technology has been used 10 well times in tight oil reservoirs in western China, including 3 well times of key exploration well stimulation, and 7 well times of old well repeated fracturing, all the treatments have achieved good effect. Among them, one well worth special note, this well had no production before fracturing, but obtained a high production of 42t a day after fracturing. During the shutdown of well, the fracturing fluid in the artificial fracture network can contact fully with micro-pores in the matrix and displace the oil in them through imbibition to the fracture system, then the oil can flow along the fracture network to the well bottom.\u0000 The high efficient imbibition fracturing technology for tight oil reservoir is a revolution in fracturing. With fracturing fluid system and well shutdown different from traditional fracturing, this technology can enhance fracturing effect and more importantly oil recovery. This paper has great guidance and reference significance for engineers and researchers engaged in tight oil development.","PeriodicalId":11006,"journal":{"name":"Day 3 Wed, June 27, 2018","volume":"55 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90771916","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}