Xu, Wei (CNOOC Research Institute Co., Ltd.) | Chen, Kaiyuan (Beijing Key Laboratory of Unconventional Natural Gas Geological Evalution and Development Engineeing, China University of Geosciences Beijing) | Fang, Lei (Beijing Key Laboratory of Unconventional Natural Gas Geological Evalution and Development Engineeing, China University of Geosciences Beijing) | Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.)
The lacustrine delta sandbody deposited in the north of Albert Basin is unconsolidated due to the shallow burial depth, which leads to an ultra-high permeability (up to 20 D) with large variation and poor diagenesis. Log derived permeability differs greatly with DST results. Thus, permeability simulation is challenging in 3D geomodeling. A hierarchical geomodeling approach is presented to bridge the gap among the ultra-high permeability log, model and DST results. The ultimate permeability model successfully matched the logging data and DST results into the geological model.
Based on the study of sedimentary microfacies, the new method identifies different discrete rocktypes (DRT) according to the analyis of core, thin section and conventional and special core analysis (e.g., capillary pressure). In this procedure, pore throat radius, flow zone index (FZI) and other parameters are taken into account to identify the DRT. Then, hierarchical modeling approach is utilized in the geomodeling. Firstly, the sedimentary microfacies model is established within the stratigraphic framework. Secondly, the spatial distribution model of DRT is established under the control of sedimentary microfacies. Thirdly, the permeability distribution is simulated according to the different pore-permeability relation functions derived from each DRT. Finally, the permeability model is compared with the logging and testing results.
Winland equation was improved based on the capillary pressure (Pc) data of special core analysis. It is found that the highest correlation between pore throat radius and reservoir properties was reached when mercury injection was 35%. The corresponding formula of R35 is selected to calculate the radius of reservoir pore throat. Reservoirs are divided into four discrete rock types according to parameters such as pore throat radius and flow zone index. Each rock type has its respective lithology, thin section feature and pore-permeability relationship. The ultra-high permeability obtained by DST test reaches up to 20 D, which belongs to the first class (DRT1) quality reservoir. It is located in the center of the delta channel with high degree of sorting and roundness. DRT4 is mainly located in the bank of the channels. It has a much higher shale content and the permeability is generally less than 50 mD. Through three-dimensional geological model, sedimentary facies, rock types and pore-permeability model are coupled hierarchically. Different pore-permeability relationships are given to different DRTs. After reconstructing the permeability model, the simulation results are highly matched with the log and DST test results.
This hierarchical geomodeling approach can effectively solve the simulation problem in the ultra-high permeability reservoir. It realizes a quantitative characterization for the complex reservoir heterogeneity. The method presented can be applied to clastic reservoir. It also plays a significant positive role in carbonate reservoir characterization.
Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Xu, Wei (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Fang, Lei (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC International Limited)
In complex clastic reservoirs, deviation often exists in oil saturation derived from logging interpretation due to the borehole conditions and log quality. Especially in thin-sand reservoirs, oil saturation is generally lower than actual results because of boundary effect. An innovative approach of saturation height function coupled with rocktype is provided to improve the accuracy of saturation prediction in well logs and spatial distribution. The model results are compared with log derived results.
The new approach is based on the routine and special core analysis of over 100 core samples from the complex clastic reservoir in the north of Albert Basin in Uganda. Discrete rocktypes (DRT) are determined by flow zone index and pore throat radius which indicate the fluid flows. After converting the capillary pressure (Pc) data to reservoir conditions, Lambda curve fitting (Sw = A * PcB + C) is used to fit each capillary pressure curve. Then, a robust relationship between the fitting coefficients (A, B, C) and rock properties (i.e. porosity and permeability) is expressed as a nonlinear function for each DRT. Combined with the height above free water level, a water saturation (Sw) model is constructed by SHF within DRT model.
Using the porosity and permeability obtainedfrom routine core analysis, FZI and pore throat radius are calculated (e.g., by Winland function). Five different rocktypes (DRT1-5) are defined in the delta sand reservoir in the north of Albert Basin with distinct pore textures. The distinguishment is in accordance with the shape of capillary pressure curve, that is, the flow capability increases from DRT1 to DRT5. A strong correlation between Pc and Sw processed by Lambda curve is acquired for each core sample. Meanwhile, 3 coefficients A, B and C can be obtained in Lambda formula. By nonlinear regression, coherent relation between each factor and reservoir properties (porosity and permeability) for each DRT are obtained. Height above the free water level is estimated by geometrical modeling on the oil water contact. The Sw model is constructed by the new SHF function coupled with DRT model. It showed that the water saturation derived from SHF is highly consistent with log derived results and NMR results. Moreover, it provides more precise results in thinner sands and in spatial distribution.
Based on the identified different rocktype, a new SHF derived from capillary pressure data is utilized to establish the relationship between saturation, the height above the free water level and rock properties. The approach can significantly improve the accuracy of saturation prediction of thin reservoir and reasonably depict the spatial distribution characteristics of saturation. Furthermore, the approach will provide a more precise result in hydrocarbon volume calculation and numerical simulation.
Africa (Sub-Sahara) Oranto Petroleum has signed two production-sharing agreements (PSAs) with Uganda for oil and gas exploration around Lake Albert, the Nigerian company said. The deal covers the Ngassa Shallow and Ngassa Deep plays in blocks near the southern part of Lake Albert, according to the Uganda Ministry of Energy and Mineral Development. The pacts closely followed the signing of a PSA by Australia's Armour Energy that covers the Kanywataba block, a 133-square-mile area that was relinquished by three international companies in 2012 after failed exploration attempts. The agreements with Oranto and Armour involve acreage that was offered in Uganda's first competitive exploration licensing round last year. Uganda discovered oil in 2006 in the Albertine rift basin along the Democratic Republic of Congo border.
Xu, Wei (CNOOC Research Institute Co., Ltd.) | Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Fang, Lei (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC Research Institute Co., Ltd.)
The Albert Basin of Uganda is located at the northern end of the western branch of the East African Rift System. It is a graben rich in oil and gas with a shallow research degree. In the south of the basin, a fan delta system controlled by the boundary fault is developed in the Miocene formation. Due to the few wells and poor quality of seismic data in this area, it is difficult to predict the spatial distribution of sedimentary reservoir sands. In this paper, sedimentary forward modeling coupled with 3D geological modeling is used to provide new ideas for reservoir prediction.
Sedimentary facies analysis is based on core description, well logs, paleontology, heavy mineral content and grain size data. Quantitative analysis of accommodation space, source supply, and sediment transport parameters can help explain the main factors that controlled the sedimentation. Milankovitch cycle method was used to establish the time scale of the basin. The simulation results were combined with 3D geological modeling to quantify the characteristics of the sand body distributions.
Sedimentary facies analysis shows that the Miocene formation in the south of Albert Basin deposited in a shallow lacustrine environment. A proximal fan delta deposition with subaqueous distributary channels was controlled by the east boundary faults. Firstly, the accommodation space was estimated according to the thickness of the stratum and the change of the ancient water depth. The source supply was estimated by the area of the project and formation thickness, and the transportation parameters were estimated according to the nonlinear transportation model based on the traction flow with a little gravity flow. Secondly, an astronomical stratigraphic framework of the Miocene strata in the south of Albert basin was established through the Milankovitch cycle stratigraphy, and it was used to restrain the process of stratigraphic forward modeling and to reproduce the sedimentary evolution process in the geological historical period. Thirdly, the stratigraphic forward modeling results were resampled into the geological model, a 3D reservoir probability distribution model is established from trend modeling to quantitatively characterize the spatial distribution of sand bodies. Finally, the sandstone distribution simulation results were transformed into quantitative control constraints for 3D geological facies modeling. Thus, the new approach significantly promotes the facies model quality and provides robust results for petrophysical property models.
Integration of stratigraphic forward modeling with 3D geological modeling can effectively solve the problem of reservoir characterization in an early stage of oilfield development through the interaction of the dual model coupling. This method has unique advantages in the reservoir research in the area with fewer data and great variation of sand.
Is Surfactant Environmentally Safe for Offshore Use and Discharge? The current presentation date and time shown is a TENTATIVE schedule. The final/confirm presentation schedule will be notified/available in February 2019. Designing Cement Jobs for Success - Get It Right the First Time! Connected Reservoir Regions Map Created From Time-Lapse Pressure Data Shows Similarity to Other Reservoir Quality Maps in a Heterogeneous Carbonate Reservoir. X. Du, Y. Jin, X. Wu, U. of Houston; Y. Liu, X. Wu, O. Awan, J. Roth, K.C. See, N. Tognini, Shell Intl.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Total E&P Uganda (hereinafter refered to as the Company) is developing oil fields in western Uganda, in an area that lies partially within the Murchison Falls National Park (MFNP) inhabited by many species of wildlife. Due to the sensitivity of the area, the Company is committed to implementing its project in line with International Finance Corporation (IFC) standards by applying the mitigation hierarchy principles. Critical Habitats might potentially be impacted by the project. The Environment and Social Impact Assessment (ESIA) is therefore undertaken to i) Give opportunities to mitigate impacts at design stage and ii) Provide visibility on how Company will achieve its commitments.
The ESIA process fulfills the Ugandan legal requirements but is also undertaken in line with the IFC Standards. As the development will occur in an area where Critical Habitat has been identified, the Company is committed to achieving No Net Loss (NNL)/ Net Gain (NG) on key biodiversity values. The assessment of NNL/NG has been done in a phased approach starting with a pre-feasibility assessment to identify potential suitable metrics, to be followed by the biodiversity loss/gain accounting for residual impacts. Results shall be used to guide impact mitigation so as to achieve NNL/NG.
The ESIA process is undertaken by an external contractor with his Ugandan partner; and the NNL/NG calculations by a biodiversity technical expert contractor. The ESIA and biodiversity expert contractors are hereinafter referred to as external contractors. Due to two processes being merged into one, the Company has to ensure advance planning and coordination between the external contractors.
It is important that the ESIA process provides the necessary input to the NNL/NG calculations, and that the output of the NNL/NG calculations is used during impact mitigation iteration. The above should take place through close collaboration between the external contractors at impact assessment stage. The ESIA has recently entered into it and the external contractors are to work together from definition of method until ESIA submission. The results of the impact assessment and recommended mitigations should therefore present the whole picture and guide the Company in order to reach NNL/NG.
In addition, as part of the ESIA process, surveys have been undertaken in order to confirm biodiversity values on ground and work iteratively with the project design team to favor early impact avoidance; which ultimately contributes towards NNL/NG.
The initial interactions between the external contractors look quite promising, as everyone is ensuring they contribute to optimize the process so that the outcome is used in order to guide and discuss mitigation requirements with project design team during the design phase.
It is the Company's understanding that combining the two processes is not common, yet it is tried for this development. This is to allow a more optimized planning and support decision making with full visibility on potential challenges, opportunities and related costs.
Water influx from a shallow sandstone formation caused problems in the Western Region of Abu Dhabi. Four wells were drilled in one field and have consistently recorded water flow issues causing Non-Productive Time. This paper looks into the problems recorded in the Drilling Reports and End of Well Reports and provides a technical proposal to combat the problems. The Asmari Formation is encountered in the 26" hole section and is normally cased off with 20" casing. The water influx problems which were in some instances combined with losses not only hampered the drilling operations but also resulted in poor cement jobs requiring remedial actions and challenging well abandonment. The main objectives are; i. Drill the 26" hole section through the Asmari Formation and cement the 20" casing to surface with no water influx and no mud losses ii. Cementing the 20" casing to surface and eliminate remedial cement jobs The approach described in this paper to achieve the above mentioned objectives was derived from three technical drilling disciplines, Drilling Fluids System, Cement Slurry Design and Operational Practices. The proposed approach was successfully applied to the recent well drilled in the field in 2016/2017. This is illustrated in the case study at the end of this paper which clearly shows that the objectives were fully met.
Davison, J. M. (Shell Global Solutions International B.V.) | Salehabadi, M. (Shell UK Exploration & Production) | De Gennaro, S. (Shell UK Exploration & Production) | Wilkinson, D. (Shell UK Exploration & Production) | Hogg, H. (Shell UK Exploration & Production) | Hunter, C. (Shell UK Exploration & Production) | Schutjens, P. (Shell Global Solutions International B.V.)
ABSTRACT: At the end of field life, wells require permanent plugging and abandonment (P&A) as part of decommissioning activities. Some UK fields developed in the 1970’s are reaching their end of field life, with UK industry estimates predicting well P&A costs over the next 30-40 years of 24 billion dollars. As well as the high financial cost, there is a significant HSSE exposure to ensure safe and reliable P&A such that no escape of hydrocarbons is possible to the near surface environment.
This paper discusses the role Geomechanics has to play in potentially reducing well P&A costs, but also ensuring integrity of the wells and formations over long time scales. Recent experience in the UK North Sea has highlighted the requirement for detailed geomechanical knowledge of the field. We will focus on three key areas for geomechanical analysis. Firstly, we discuss reservoir pressure re-charge and in-situ stress response, from simple pressure-depth plots to more complex 3-D numerical modelling of the stress changes in reservoirs and surrounding formations. An added level of complexity compared to ‘conventional’ geomechanical modelling is the ability to forward predict the reservoir pressure recharge over hundreds of years and the commensurate response of the in-situ stresses. Secondly, as well as the modelling of stress changes over time, Geomechanics has a key role to play in determining the opportunity of using shale creep deformation to create annular barriers in the place of cement. Lastly, in some cases the preferred P&A design for a well is not possible due to well access issues which then requires cross-flow analysis linked with the geomechanical response of permeable formations. This approach is required for containment risk assessment and application of ‘as low as reasonably practicable’ (ALARP) assessments for well and formation integrity. Each of these subjects will be covered with field examples from the UK North Sea which demonstrate the Geomechanical workflows employed and the impact these have had on the business.
Li, Jinxiang (CNOOC Uganda Limited) | Yin, Fei (MOE Key Laboratory of Petroleum Engineering, China University of Petroleum-Beijing) | Gao, Deli (MOE Key Laboratory of Petroleum Engineering, China University of Petroleum-Beijing) | Yang, Zhi (CNOOC Uganda Limited) | Xiang, Ming (CNOOC Uganda Limited) | Huang, Chuanchao (CNOOC Uganda Limited)
Fault reactivation is an unfavorable incident during petroleum well drilling and production because the reactivated fault imperils the well integrity potentially. Coring and rock mechanics experiments are performed to obtain the rock properties of the fault in a Uganda oilfield. The three-dimensional finite element model of directional wells passing through reactivated faults is established. The mechanical behaviors of wells under various scenarios are analyzed by numerical simulation. The influence rules of slip displacement of fault, well inclination angle, wall thickness of casing, steel grade of casing and property of cement sheath on mechanical state of wells through faults are revealed. Research results indicate that decreasing the intersection angle between directional well and fault plane and employing cement sheath with low elastic modulus can enhance well integrity effectively. The research achievements provide the integrity assessment method and mitigation measures for the directional wells through reactivated faults.