Africa (Sub-Sahara) United Hydrocarbon International finished drilling the Belanga North-1 exploration well located in Doba basin in southern Chad. The well was drilled to a total depth of 1392 m, and encountered three oil-bearing sand intervals--two in the targeted Upper Cretaceous "YO" sands and one in an untested shallower sand. United Hydrocarbon (100%) is the operator. Asia Pacific China National Offshore Oil Corporation discovered natural gas in the Qiongdongan basin, South China Sea. Well Lingshui 17-2--located in the east Lingshui sag portion of the basin at an average water depth of 1450 m--was drilled and completed to a depth of 3510 m. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%). Philippines National Oil Company (PNOC) has begun drilling operations on its Baragatan-1 exploration well on service contract 63, offshore Palawan Island, west of the Philippines, using the Naga 5 jackup rig.
Africa (Sub-Sahara) BG Group discovered gas in the Taachui-1 well and sidetrack in Block 1, offshore Tanzania. The drillship Deepsea Metro Idrilled Taachui-1 close to the western boundary of Block 1, then sidetracked the well and drilled to a total depth of 4215 m. The well encountered gas in a single gross column of 289 m within the targeted Cretaceous reservoir interval. Net pay totaled 155 m. Estimates of the mean recoverable gas resources are around 1 Tcf. Statoil (65%) and co-venturer ExxonMobil (35%) made a sixth discovery--the Piri-1 well--in Block 2 offshore Tanzania. Piri-1 was drilled by drillship Discoverer Americas, at a water depth of 2360 m.
Africa (Sub-Sahara) Eni Congo discovered oil at its Minsala Marine 1 well offshore the Republic of the Congo in Marine XII Block 12 km from the operator's recent Nené Marine discovery. Minsala intersected 420 m of gross pay and encountered light oil in a Lower Cretaceous presalt sequence. The well reached a total depth of 3700 m. Eni (65%) is operator, with state-owned partner SNPC 25%), and New Age (African Global Energy) Limited (10%). SOCO EPC's Lindongo X Marine 101 Well (LXM-101)--located offshore the Republic of Congo in Marine XI Block--encountered oil in a clastic sequence of the Djeno sands, with early log interpretation indicating approximately 50 m of gross pay.
Africa (Sub-Sahara) Tullow's Cheptuket-1 well in Block 12A of northern Kenya has encountered good oil shows over an almost 2,300‑ft interval, the company reported. The first well to test the Kerio Valley Basin, Cheptuket-1 was drilled to a final depth of 10,114 ft. The results indicate the presence of an active petroleum system with significant oil generation, the company said. Post-well analysis now under way will affect future basin exploration decisions. Tullow is the block operator with a 40% interest. Delonex Energy (40%) and Africa Oil (20%) are the other participants.
Chullabrahm, Pattarapong (PTT Exploration and Production Public Company Ltd) | Saranyasoontorn, Korn (PTT Exploration and Production Public Company Ltd) | Svasti-xuto, Maythus (PTT Exploration and Production Public Company Ltd) | Trithipchatsakul, Chao (PTT Exploration and Production Public Company Ltd) | Sunderland, Damon (Arup Pty Ltd) | Ingvorsen, Peter (Arup Pty Ltd) | Madrigal, Sarah (Arup Pty Ltd) | McAndrew, Russell (Arup Pty Ltd)
This paper presents an integration of geology, geohazards, geophysics and geotechnical assessments for a design of an offshore gas production facility and an associated export pipeline. The gas field described in this paper is located off the North West coast of Australia in the Timor Sea in a water depth of approximately 130m.
Various resource development options were investigated during the Concept Select / pre-Front End Engineering Design (pre-FEED) phase of the project. These options included fixed and floating structures in the infield area and a 300km long export pipeline that ties into an existing gas trunkline connecting to an onshore processing plant.
To provide the necessary engineering due diligence to allow the project to progress further, several phases of geo-related investigations were undertaken to assess various geohazard challenges and foundation risks. Some of these challenges include a pipeline route traversing several steeply sloping seabed canyons, potential activation of turbidite sequences, and the presence of very soft carbonate sediments to calcarenite rock.
This paper describes these ground related challenges and how they were constrained through the geo-related investigations conducted, observations made and results obtained. Ground related challenges are described in two parts: Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; and Staged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; and
Staged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Key benefits of conducting an integrated approach to geo-related challenges on a complex site will also be presented in this paper.
The selection of completion equipment for artificial lift string for any field in the oil and gas industry is important for the safe and reliable operations of such a field. This is critical to the management and overall profitability of the oil and gas asset, especially in areas where artificial lift is the predominant means of water injection and hydrocarbon production. This paper focuses on why it is important to understand the saline subsurface and the total dissolved solids (TDS) of the environment in which the artificial lift completion is to be deployed and its impact on equipment selection.
High concentration of corrosive components in the well fluid such as hydrogen sulfide, chlorine and total dissolved solids makes the well fluid conducive for electron migration. Such migration causes heavy corrosion, especially when dissimilar metals are used in artificial lift well completions. Carbon steel tubulars and casing are easily affected by such corrosive composition and leads to premature failure of artificial lift completions, which poses safety and operational issues. This type of environment is intense in electrical submersible pump completed wells because of the electromagnetic field generated by the current passing through the electrical cable of the pump system.
A combination of field and laboratory data gathering, and analysis was utilized to determine the effect of the aggressive components of the produced fluid on electrical submersible pumps assembly. The contributions of the high total dissolved solids in the conductivity of the well fluid, and in the electrochemical process for metal corrosion were analyzed. It was evident from both forms and approaches utilized in the analysis that well fluid becomes an electrolyte that provided the desired path for electron flow, which was enhanced by the magnetic field of the ESP system cable.
This paper highlights the integration of three approaches of geochemical analysis of well effluent, Anodic Index differential and tubular internal coating in corrosion prevention and electric submersible pump runlife elongation in wells with corrosive compositions including high total dissolved solids.
The Cooper Basin of Australia is challenged by strike-slip to reverse stress regimes, adversely affecting hydraulic fracturing treatments. In drilling, the high deviatory stress conditions increase borehole breakout, affect log acquisition and impact cementing job quality. The non-favourable stress conditions in conjunction with natural fracturing result in: complex fracturing (with shear and sub-vertical components); high near-wellbore pressure loss (NWBPL) values; and stimulation of lower permeability, low modulus intervals (e.g., carbonaceous shales, interbedded coals) in preference to the targeted and higher modulus, tight-gas sandstones. Typically, vertical wells have been employed in past completions of the Cooper Basin as well as in the offsetting areas to the case study in the Windorah Trough, Southwest Queensland.
We will present the results from two case study wells offsetting a previous vertical well where well trajectory, completion and fracture design changes were employed in an ongoing experiment to improve job execution for Patchawarra tight gas reservoir treatments in the Cooper Basin. The two wells were directionally deviated at 31° and 25° final inclinations from vertical with azimuth <10 deg from the maximum horizontal stress direction, as determined from offsetting well data. To better define sections with limited, poor or missing log data (because of difficult hole conditions), drilling data, logging while drilling (LWD) gamma ray data, openhole conventional and dipole sonic logs, along with prior 1D stress data were used with a machine learning model to improve stress profiling and reservoir characterization. Next, perforations were shot 0 and 180° phased along the wellbore and initial fluid viscosity was increased to better align the hydraulic fracture and reduce NWBPL, respectively. Finally, diagnostic fracture injection tests (DFIT) were performed in sections of varying moduli below and in the zone of interest in order to verify the horizontal strains and calibrate the final 1D stress profile prior to stimulating both wells.
The improved well and perforation alignment to the maximum horizontal stress direction has improved reservoir connection, lowered NWBPL in some cases, and in some cases improved fracture containment. Decreasing injection rates and minimizing perforated intervals has improved targeting of desired intervals; however, overall fracture widths remain low and continue to be sensitive to proppant sizing and concentrations with several screen outs experienced. This experimentation has resulted in short-term production improvements in the wells using 4- and 3-stage treatments relative to the offsetting vertical well where a 5-stage treatment was executed.
Unconventional gas exploration in the Cooper Basin, Australia, has historically concentrated on fracture stimulation of tight gas sandstones within mapped structural closures. In drilling these sandstones, and other clastic reservoir targets, it has been recognised for many years that the Permian coal measures of the Toolachee, Epsilon and Patchawarra Formations record high levels of gas, often in excess of 4000 units, encountered at depths between 2500 and 3500m. Unlike shallower Coal-Seam-Gas reservoirs, which rely on de-pressuristion through de-watering to liberate adsorbed gas from the kerogen surface, deep coals are a "dry" system in which the free gas component is produced via kerogen and fracture permeability.
However maintaining a consistent and commercial flow rate from deep coals alone remained enigmatic until the first dedicated fracture stimulation program of deep Permian coals was commenced in the Moomba Field in 2007. Understandings of Permian source-rock reservoirs, the roles of the coal type and rank on sorption capacity and porosity, the influence of effective pressure and depth on coal permeability and the interrelation of coal fracture permeability with in-situ stress and mechanical stratigraphy has now advanced.
The deep Permian coal fairway in the Patchawarra and Nappamerri Trough of the Cooper Basin has been defined and mapped using a generative potential approach within a comprehensive 3D basin model. Net coal thicknesses from log electro-facies for 879 wells has been combined with available well maturity, TOC, HI and kerogen kinetic data, and calibrated against corrected temperatures in a basin-wide Trinity retention model which incorporates 14 mapped regional horizons. Play fairways have been overlain with observations of in-situ stress direction and fracture orientations from 3D seismic curvature volumes, FMI data and stress states from Mechanical Earth Models (MEM).
Within the basin, this approach has defined a P50 in-place resource of 14.6 TCF of gas and a P10 of 20.7 TCF of gas within the deep coals of the Permian Toolachee, Epsilon and Patchawarra Formations in Senex permits, of which 8-11 TCF is within the North Patchawarra Trough. MEM's have also demonstrated that deep coal seams are consistently in a normal stress state and therefore provide excellent scope for both propagating and constraining vertical fracture growth. Work is now underway to define further those areas, within the mapped resource parameters, which provide the best opportunity to site pilot lateral wells for multi-stage fracture stimulation within deep coals.
Pan, Zhejun (CSIRO Energy) | Heryanto, Deasy (CSIRO Energy) | Down, David (CSIRO Energy) | Connell, Luke (CSIRO Energy) | Camilleri, Michael (CSIRO Energy) | Tan, Yuling (CSIRO Energy) | Sander, Regina (CSIRO Energy)
Cooper Basin is one of the most important onshore oil and gas producing basins in Australia. It also has the most prospective unconventional tight gas and shale gas opportunities. As tight sandstones or gas shales have low permeability, understanding the permeability behaviour is important for the production of these gas resources. In this work, tight sandstone and shale samples were obtained from an exploration well in the Cooper Basin, Australia, and they were cut into cubic samples with about 30 mm on each side using a wire saw. The cubic sample was then placed in a 3D printed membrane, therefore, permeability along each directional axis can be measured. Methane was used to characterise the permeability. Effects of gas pressure and effective stress were studied with gas pressure up to 9.5 MPa and effective stress up to 7.0 MPa. The results shows that the shale has strong permeability anisotropy at different direction. The sandstone sample also showed anisotropic behaviour, but not as significant as the shale. Finally, a reservoir simulator, SIMED II, is used to study the gas production from tight sandstone and shale using hydraulic fractured vertical and horizontal wells. The simulation results show that permeability plays a critical role in the gas production behaviour from tight sandstones and shales.