Xiao, Yong (China Zhenhua Oil Co., Ltd) | Wang, Hehua (China Zhenhua Oil Co., Ltd) | Guo, Jianchun (State Key Laboratory on Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lu, Lize (China Zhenhua Oil Co., Ltd) | Cheng, Yi (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd.) | Chen, Mengting (Borehole Operation Branch Office of Sinopec Southwest Petroleum Engineering Co., Ltd.) | Fan, Fengying (Chengdu Northern Petroleum Exploration and Development Technology Co. Ltd.) | Xue, Heng (China Zhenhua Oil Co., Ltd)
The low permeability reservoir of Ahdeb field discovered in the 80's, has more than 250 active wells with low initial production and rapid decline compared to other reservoirs. Matrix acidizing is the main stimulation method to recover and enhance production performance in Ahdeb oilfield, but short-distance deblocking acidizing can't communicate with the deep reservoir, and it is impossible to expand the effective seepage radius. Therefore, High reservoir heterogeneity, low permeability, poor pore pressure necessitates the move from conventional matrix stimulation to acid fracturing technology targeting better fracture conductivity and deep penetration for effective productivity and recovery enhancement.
The acid fracturing feasibility research shows that the interlayer characteristics, lithologic barrier, stress barrier and oil-water relationship of the low permeability reservoirs are favorable for fracture initiation, expansion and geometry control. Acid fracturing is one of the best ways to stimulate the potential production in low-permeability reservoirs of the Ahdeb oilfield. The acid fracturing optimization includes fracture conductivity, fluid system and fracturing parameters. Pad acid fracturing and gel acid with multi-stage alternating and closed acid fracturing are the suitable technologies for low permeability reservoir stimulation.
An experiment well has been simulated and designed, and the expected production increase is 1.5 times. Base on this paper's research, a wide-scale development strategy will be planned, and many wells will be stimulated for increase the production performance.
Visuray is using its unique X-ray technology to improve downhole imaging. A company is selling a new well testing tool designed to be a cheaper, simpler way to do fiber optic sensing, and then it fades away. BP has seen enormous payoff from a program to intervene in underperforming subsea wells in the Gulf of Mexico. A coiled-tubing selective perforating and activation system that transmits critical downhole data and measurements in real time is enabling well interventions that previously could not have been executed. Development of a new polymer composite that degrades via hydrolysis in hot water or brine holds potential for use in structural applications for intervention-less downhole tools.
Petrobras and Shell have brought online the Lula field’s seventh FPSO as the firms continue to ramp up production from the pre-salt Santos Basin. The French major is racking up barrels of deepwater production as part of its large-scale West African push. This paper describes how a technique known as applied-surface-backpressure managed-pressure drilling (ASBP-MPD) can alleviate the limitations of conventional deepwater well control. Majors BP and Chevron have overcome development challenges and delays to launch their respective Clair Ridge and Big Foot projects. The unit is flowing oil and gas from the Lula Extremo Sul area, 290 km off Rio de Janeiro state in 2150 m of water.
Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
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.
Automated pressure transient analysis (PTA) with real-time data feed from permanent downhole gauge (PDHG) enables continuous monitoring of well and reservoir that facilitates timely surveillance decisions. However, while robust automation of the process is critical to minimize the requirement of manual efforts, a challenge lies in automatic diagnostics of a log-log plot which is often contaminated by non-reservoir response such as wellbore dynamics. We propose a new automatic PTA method to enhance accuracy of diagnostics.
The method utilizes a pattern detection method based on similarity search and automatically identifies sequence of flow regimes, such as radial, spherical or linear flow etc., on a log-log diagnostic plot of pressure and derivative. To discover individual flow regimes, the algorithm scans a window on the plot and finds a pattern that is most similar to a ‘motif’ defined for the flow regime. Such motifs are known for individual flow regimes from analytical models. During the similarity search, the algorithm ensures that the discovered sequence of flow regimes is consistent with the flow scenario anticipated at the well.
The proposed method is implemented in fully automated PTA workflow. First, the system reads PDHG pressure and flow rate at a well. Then, pressure buildup intervals are automatically identified. Subsequently, a log-log diagnostic plot is automatically generated for each buildup and the proposed method is executed. Once a sequence of flow regimes is identified, the algorithm locates a horizontal line over the radial flow regime and calculates permeability, skin and extrapolated pressure p*. For horizontal wells, effective completion length is also computed by locating a half slope line on the linear flow regime. For hydraulically fractured wells, fracture length or fracture conductivity is estimated from the linear or bi-linear flow regime. The results are written on output files or to a database together with identified flow regimes visualized on plots for the review of reservoir engineers. The method is tested on oil producers with high water cut where significant fluid segregation or crossflow is impacting log-log diagnostic plots, as well as gas wells where a pressure leak during buildup is contaminating pressure derivatives. Despite such noise of non-reservoir responses, the proposed method successfully identifies flow regimes on most of buildups and produces PTA results comparable to manual analysis.
Compared to existing automatic PTA methods, such as automatic matching of model response or automatic semi-log analysis of radial flow regimes identified by user-specified criteria, the proposed method is particularly robust to use with pressure data which is significantly contaminated by non-reservoir responses. Such robustness of our method is achieved by a flexible pattern search for individual flow regimes rather than matching an entire model response all together or requiring rules specified by engineers.
Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
Basin simulations, reservoir simulations, laboratory measurements and field measurements are crucial details needed for making good operational decisions in frontier areas. Seismic reservoir characterization is the task that combines engineering, geological and geophysical data. Basin simulation gives the geoscientist the opportunity to incorporate sophisticated modeling into their predictions of subsurface properties. This simulation technique normally uses a regional seismic interpretation as an endpoint for a compaction, temperature, pressure or mineralogical forward model that has engineering and geophysical calibrations. Reservoir characterization work often produces multiple interpretations, using various techniques, of the same volume of the earth. How should these interpretations be combined? Which interpretations should carry more influence?
The technological challenge of using basin simulation output with traditional seismic inversion is that the exact location of facies is not accurate. Therefore, the derived static low frequency model constructed using rock physics transforms leads to an inversion product with unphysical artifacts at worst and at best, a reiteration of the basin model with slight property variations from the seismic amplitude input conspicuously overlying.
We present an inversion that utilizes a Bayesian framework to iteratively constructs a facies and impedance model using prior estimates of facies distribution and impedance uncertainty. This framework allows the spatial variability of properties from the basin model to be included in the inversion without introducing localized artifacts. The benefit of using a Bayesian framework in deterministic inversion at seismic resolution is that priors may be considered in order to disqualify unphysical or unlikely yet acceptable solutions from the non-unique solution space. In this application, the prior is constructed using facies specific porosity compaction trends, cement profiles based on temperature and timing and pore pressures, transformed with rock physics models to elastic properties. With these facies property volumes, we produce unique probability density functions at every seismic sample. Given the seismic input and additional priors, the inversion produces a most probable facies volume and impedances (Vp-Vs-Density). The resulting properties are thus an integration of a complex basin simulation model with a deterministic seismic inversion.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 206A (Anaheim Convention Center)
Presentation Type: Oral
Cornelius, Sharon (Department of Earth and Atmospheric Sciences, University of Houston, Houston, Texas) | Castagna, John P. (Department of Earth and Atmospheric Sciences, University of Houston, Houston, Texas) | Emmet, Peter A. (Department of Earth and Atmospheric Sciences, University of Houston, Houston, Texas)
Composite medium modeling of mixed salt-body mineralogies and multiple regression analysis lead to the conclusion that this velocity variation can be explained by the lithological variation within the salt, which also varies by latitude.