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Africa (Sub-Sahara) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
Africa (Sub-Sahara) Bowleven said that its extended flow test program at the Moambe and Zingana wells on the Bomono Permit onshore Cameroon is complete. The company said that the results to date continue to support its plans for an initial supply of between 5 MMscf/D and 6 MMscf/D of natural gas for power generation, under a development program established with partners Actis and Eneo. The initial program focuses on production from the shallower gas-prone sands on the permit. Bowleven has a 100% equity interest in the permit. Eni started production from the West Hub development project's Mpungi field in Block 15/06 offshore Angola. The startup follows the project's first oil from the Sangos field in November 2014 and the Cinguvu field last April.
Africa (Sub-Sahara) Eni started production from the West Hub development project's Mpungi field in Block 15/06 offshore Angola. The startup follows the project's first oil from the Sangos field in November 2014 and the Cinguvu field last April. Mpungi will ramp up West Hub oil production to 100,000 B/D in the first quarter from a previous level of 60,000 B/D. The project also includes the future development of the Mpungi North, Ochigufu, and Vandumbu fields. Eni is the block operator with a 36.84% stake. Sonangol (36.84%) and SSI Fifteen (26.32%) hold the other stakes.
Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule.
Chen, Meiyi (College of Earth Science, Northeast Petroleum University) | Ji, Qingsheng (Exploration and Development Research Institute) | Chen, Shoutian (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation) | Qin, Longpu (Exploration Department Daqing Oilfield Company Ltd) | Cong, Peihong (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation)
Based on the seismic prediction difficulties of the tight sandstone reservoir in Fuyu formation in Zhaoyuan area, single-well sequence division and connecting-well sub-layer correlation are carried out according to logging and lithologic data, and short-cycle interface position is calibrated precisely after a mutual calibration of logging and seismic data. Horizon tracing in the whole area is also carried out to build highfrequency isochronous stratigraphic framework. On this basis, the log facies modes and the sedimentary facies of the short-cycles under a high-frequency isochronous stratigraphic framework are analyzed in the target area, sand-body geometric scale parameters and their relations and sand-body development degree are calculated out, and a sand-body geological model is also built out. According to the seismic data and layer-by-layer geological model of sand bodies, a spatial distribution probability model of facies-controlled sand bodies is built out, which is used to constrain the pre-stack seismic data in facies-controlled inversion calculation. Based on the results of facies-controlled inversion, the tight sandstone prediction is carried out. Finally, a method of isochronal facies-controlled pre-stack seismic inversion prediction of tight sandstone reservoir is formed and it realizes the effective prediction of superimposed sand bodies in target area. Compared with actual drilling results, the sandstone of more than 2m has clear depiction and the sandstone of between 1-2m also has response, which indicates that this method is feasible and practicable.
Y. Hu, Q. Gan, A. Hurst, University of Aberdeen; D. Elsworth, Pennsylvania State University Pressure transient data may be acquired from wells during exploration, appraisal and production. Each data set provides important dynamic information that facilitates the decision-making process at the various phases of reservoir development. The course will summarise the fundamentals of pressure transient analysis and discuss some of the recent advances including deconvolution. Emphasis will be placed on the value of information. The course will combine explanations of theory (with course notes), worked examples (using Excel) and presentation of real case examples from both oil and gas reservoirs.
ABSTRACT: This paper presents a coupled transient thermal-hydro-mechanical model with strain-dependent hydraulic conductivity for heavy oil formation under steam injection. 3D numerical analysis is performed for the purpose of estimating the scope of area of steam penetration into the unconsolidated sandstone formation at True Vertical Depth (TVD) depth around 200 m. This analysis is part of a pilot application of a set of Cyclic Steam Stimulation (CSS) wells, which will be converted to steam flood at a later time. The following processes are performed for simulating the coupled behavior of steam penetration in heavy oil formation: 1) Build a coupled thermal-hydro-mechanical model for simulation behavior of steam penetration in heavy oil formations. Strain-dependency properties have been introduced into the model by assigning thermal conductivity and hydraulic conductivity that both vary with related values of strain component. Strain-dependent elastic stiffness has also been implemented into the model. 2) Numerical analysis has been performed for temperature distribution caused by steam penetration with Finite Element software set. Totally 13 wells are modeled in this work. Predictions of T-contour development are made for 2 kinds of scenarios of operations of steam injection plan: First one is for the case without further steam injection but only time increase; the second one is for the case with steam injection and intermission. For both cases, there are productions of oil/liquid at other wells. The case study provides a case study for numerical modeling of steam penetration in the heavy oil formation with coupled thermal- hydro-mechanical modeling. A best practice of performing this kind of analysis with Finite Element method is presented.
The process of steam penetration in enhanced heavy oil production is complicated (Al-Hadhrami et al, 2014; Boone et al, 1995; Settari et al, 2001; and Zhao and Gates, 2013). In this process, super-heated steam, whose temperature can be as high as 250°C or even higher, is injected into the heavy oil formation. As the steam flow contacts the formation, heat transfer begins between the steam and formation along with the porous flow of steam within the formation.
The Sea Lion Field is an Early Cretaceous turbidite fan complex, located in the North Falkland Basin, 220 km north of the Falkland Islands. The reservoirs are dominated by amalgamated high density turbidites (Bouma Ta and liquefied sediment gravity flows), but also contain low density turbidites, linked debrites and interdigitated lacustrine mudstones. An integrated dynamic modelling workflow which incorporates the latest understanding of the Sea Lion Field sedimentology and reservoir heterogeneities is presented.
The workflow focuses on capturing and retaining reservoir heterogeneity throughout the reservoir modelling process. Coarse-scale heterogeneity is captured during the construction of the full-field geological (static) model and conserved in the dynamic model by using the same grid dimensions. Sedimentological features (fine-scale heterogeneity) below the grid resolution are captured in separate, 3D core-scale models. Through a process of
Detailed interpretation of the available core data enables a statistical evaluation, which underpins the construction of core-scale models for the individual rock types. The resulting 3D core-scale models are representative of the reservoir and the development concept in terms of reservoir dip, lithology, petrophysical and fluid properties and well spacing. Matching the coarse model behaviour to the core-scale model forecast is an inverse problem with multiple possible solutions; therefore, assisted history matching is a valuable tool for quickly obtaining, comparing and ranking possible upscaled relative permeability functions and
This integrated dynamic modelling workflow allows for the direct use of detailed geological models characterising the main heterogeneities impacting flow behaviour, while retaining the ability to investigate and capture small-scale heterogeneities below the resolution of the full-field static model, thus avoiding the cumbersome process of upscaling geological properties. Assisted history matching and optimization have been integrated into the workflow, providing a robust method to produce upscaled relative permeability functions that replicate the expected waterflood behaviour.
Davis, Graham (Premier Oil) | Newbould, Rob (Premier Oil) | Lopez, Aldo (Premier Oil) | Hadibeik, Hamid (Halliburton) | Guevara, Zunerge (Halliburton) | Engelman, Bob (Halliburton) | Balliet, Ron (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Imrie, Andrew (Halliburton)
The oil and gas potential of the basins surrounding the Falkland Islands has attracted exploration drilling that resulted in discovering the Sea Lion Field in the North Falkland Basin in May 2010. Recent exploration drilling has resulted in new oil discoveries to the south of the Sea Lion Complex that has not only confirmed the area as a significant hydrocarbon province but has also enhanced the likelihood of future commercial development of resources. Primary oil targets are stacked and amalgamated deepwater lacustrine turbidite fans comprising multiple lobes. In exploration and appraisal wells, porosity characterization, permeability assessment, pressure measurements, and hydrocarbon fluid identification are essential input data for robust reservoir characterizations and resource estimations.
A comprehensive suite of advanced logging measurements, in addition to conventional log measurements, have been used to facilitate data analysis and calibration to laboratory core measurements. The pressure gradients and fluid samples obtained from formation testing when combined with the wireline log measurements are fundamental when determining the thickness, quality, and connectivity of hydrocarbon zones, which, in turn, impact the commercial evaluation of the well. In these remote offshore basins where rig costs are high and the ability to focus data acquisition in specific zones of interest and minimize logging time whilst identifying and reacting early in real time to data points that lie off the expected trends can add significant value to the operating company.
Formation evaluation challenges include hydrocarbon identification and resolving fluid contact uncertainties. In addition, establishing whether there are any baffles or barriers in the system or significantly varying reservoir properties as a consequence of facies changes has the potential to complicate the evaluation in respect to permeability characterization and volume estimation.
A method of facies classification using a combination of resistivity-based borehole imaging data and nuclear magnetic resonance (NMR) data is outlined in this paper. This method, when combined with conventional log data, has exhibited encouraging results in terms of identifying lithofacies and determining a rock quality index (RQI). The mud logs and gamma ray logs were interpreted with the borehole image logs in these turbidite reservoirs, which resulted in identifying four distinct depositional lithofacies. These lithofacies were integrated with the free fluid index (FFI) to bulk volume irreducible (BVI) ratio determined from the NMR data. The FFI to BVI ratio was used as an index for RQI classification, which was then subsequently used to optimize formation pressure testing and sampling points.
The contribution and importance of lithofacies identification is typically ignored when optimizing formation pressure depths and interpreting the results. The methodology presented in this paper uses an integrated workflow jointly developed by the operator and service company that allows detailed reservoir evaluation in the zones of interest and real-time adjustments to optimize the data acquisition programme that potentially enables rig-time savings and, consequently, reduces overall formation evaluation costs.
Hadibeik, Hamid (Halliburton) | Azari, Mehdi (Halliburton) | Kalawina, Mahmoud (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Eyuboglu, Sami (Halliburton) | Khan, Waqar (Halliburton) | Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company)
Reservoir relative permeability as a function of saturation is critical for assessing reservoir hydrocarbon recovery, selecting the well-completion method, and determining the production strategy. It is a key input to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability curves at reservoir conditions is also a crucial task for successful reservoir modeling and history matching of production data. The relative permeability data estimated from core analysis may cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability curves with downhole pressure-transient analysis of mini-drillstem tests (mini-DSTs) and well-log-derived saturations.
The new approach was based on performing mini-DSTs in the free water, oil, and oil-water transition zones. Analyses of the mini-DST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, porosity and resistivity logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining all of these downhole measurements provided the relative permeability curves.
When multiphase fluids flow in a reservoir, the flow rate of each phase depends on the effective permeability of that phase (Alkafeef et al., 2016). Effective permeability is obtained from absolute permeability of a reservoir multiplied by the relative permeability. Although absolute permeability is a function of reservoir pore geometry and does not change with fluid type, relative permeability is a fluid-dependent parameter and mainly depends on fluid saturation, pore geometry, viscosity, and surface tension (Goda and Behrenbruch, 2004).