Africa (Sub-Sahara) An 816-mile 2D seismic acquisition program was completed on the Ampasindava block, located in the Majunga deepwater basin offshore northwest Madagascar. The data will provide improved subsurface imaging of the large Sifaka prospect and will potentially mature additional prospects in the Ampasindava block to drill-ready status. Sterling Energy (UK) holds a 30% interest in the Ampasindava production sharing contract, which is operated by ExxonMobil Exploration and Production (Northern Madagascar) (70%). Asia Pacific Production began on the Liuhua 19-5 gas field in the Pearl River Mouth basin in the South China Sea. The field is expected to hit peak production of 29 MMcf/D this year. China National Offshore Oil Corporation (100%) is the operator. Drilling began on the YNG 3264 and the CHK 1177 development wells onshore in Myanmar.
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. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). 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%).
Africa (Sub-Sahara) Bowleven has started drilling operations at the Moambe exploration well on the Bomono permit in Cameroon. Moambe is the second well in a two-well program, approximately 2 km east of the first well, Zingana. It targets a previously undrilled Paleocene Tertiary three-way dip fault block containing multiple sands and will be drilled to an estimated 1620 m in measured depth. Both wells will be logged. Bowleven is the operator and holds 100% interest. Asia Pacific Murphy Oil discovered gas at its Permai exploration well in deepwater Block H in the South China Sea offshore Malaysia. The find is Murphy's eighth consecutive success in the area around the Rotan floating liquefied natural gas project, which is planned to begin its first production in 2018.
Little is known about the nature and origin of microcrystalline quartz in sandstone reservoirs or mudstone reservoirs. We have utilized advanced analytical capabilities to improve our understanding of controls on microcrystalline quartz development in several examples where porosity is preserved in deeply buried sandstone reservoirs to understand the development in siliceous mudstones.
In this study, several advanced analytical techniques were used to evaluate the crystallographic and compositional controls on the formation of microcrystalline quartz. SEM/Cathodoluminescence (CL) imaging confirms that quartz overgrowths have a complex growth history. Previous workers (Kraishan et al. 2000) suggested that CL patterns in quartz cement are largely due to trace elements rather than defects and that aluminum varies consistently between each cement phase. Electron Backscatter Diffraction (EBSD) combined with Wavelength Dispersive Spectrometry (WDS) confirms that the complex banding visible in CL is not due to changes in crystallographic orientation but more likely variations in quartz composition associated with changes in pore fluid composition and/or reservoir conditions. Secondary Ion Mass Spectrometry (SIMS) analysis provides maps of ultra-trace element distribution that confirm that trace amounts of iron, manganese, and titanium can be used as proxies for defect density and temperature. Additionally, SIMS analysis provides oxygen isotope data providing insight into the initial reservoir conditions and temperature of formation of microcrystalline quartz in several formations.
Microcrystalline quartz in the form of replacement, micropore, and overgrowth cements is present in the Wolfcamp A in the southern Delaware Basin. The amount of cementation has an effect on the reservoir quality and appears to have an impact on the petrophysical properties. The siliceous mudstones are comprised predominantly of biogenic silica (sponge spicules, radiolarians, which are the silica sources for the authigenic microcrystalline quartz), detrital grains (quartz and feldspars), pyrite framboids, and organic matter.
Integrating the results from these advanced analytical techniques has helped us develop our understanding of the processes controlling the formation of quartz cement and improved our ability to reconstruct the reservoir diagenetic history of quartz growth leading to a proposed model for predicting porosity preservation in deep, hot sandstone reservoirs and the formation of microcrystalline quartz in siliceous mudstones. This is the first research to report on spatially resolved isotopic analysis of silica cements integrated into a petrographic framework and a proposed mechanism for microcrystalline quartz growth.
The Cretaceous Eagle Ford of South Texas is a major unconventional play. Age equivalent rocks are present in the adjacent Burgos Basin, Mexico along with other unconventional targets in the Jurassic. The objective of this study was to map areas of unconventional potential from basinwide maturity predictions provided by 3D modeling. This study has identified oil, wet gas and dry gas areas of interest for the Cretaceous and Jurassic targets. These areas of interest can then be used to focus followup studies by companies or institutions evaluating joint ventures and/or lease sale blocks in the basin.
The 3D model for the Burgos Basin was made using publicly available information. Regional structure maps were made by integrating published structure maps and cross sections. Structure maps, temperature gradients from well logs and a tertiary erosion map were the key inputs used to model maturity. The Cretaceous Agua Nueva and the Jurassic La Casita/Pimienta Formations were the primary zones of interest. Rock maturity data was available for one Cretaceous and one Jurassic well. The model was also verified by comparing to Cretaceous and Jurassic unconventional well results.
Structural strike of the Eagle Ford in south Texas is southwest to northeast. Near the border structural strike abruptly changes to nearly north - south. In the Burgos Basin, the Mesozoic section dips eastward toward the Gulf of Mexico due to over 30,000 feet of Tertiary sand and shale deposition. Faulting in the Tertiary section generally soles out above the Mesozoic, so the Mesozoic is mostly tectonically undisturbed which is favorable for unconventional targets.
The prospective area for the Cretaceous and Jurassic is essentially coincident and is over 40 miles wide and 300 miles long. The prospective area was defined according to depth and modeled vitrinite reflectance equivalence (VRE). Measured depths of 5,000 to 15,000 feet and VRE greater than 0.8 were used. The rationale was that shallower than 5,000 feet would have low pressure and temperature and greater than 15,000 feet would have too high a well cost for horizontal wells. The oil prospective area is from 0.8 to 1.1 VRE, wet gas from 1.1 to 1.7 VRE and dry gas over 1.7 VRE. Oil spacing was assumed to be 100 acres and gas spacing 200 acres. Total recoverable resources are estimated at approximately 27 BBOE of which 15% are liquids (oil and condensate) and 85% are gas.
The Jurassic age Hanifa and Tuwaiq Mountain Formations are regionally established source rocks that charged majority of the oil fields in the region. These formations are comprised of dark carbonate mudrocks with high organic richness and dominantly calcite mineralogy. Several studies were conducted regionally to evaluate the potential of these Jurassic intervals as an unconventional play.
In April 2018, The Kingdom of Bahrain announced the discovery of a major unconventional resource in Khalij Al Bahrain basin following the production of light oil from Tuwaiq Mountain Formation. These results confirmed the viability of the Jurassic source intervals as an Unconventional asset. However, the nature and the location of the resource present a number of operational challenges in a region where development of unconventional resources is at its infancy. This instigates the need to address and tackle these challenges through innovative approaches to enable the effective appraisal and subsequently development of the asset.
This publication introduces the emerging unconventional play in Khalij Al Bahrain basin and discusses the adopted strategies to appraise and develop the asset. The areas for optimization considered include well design, drilling and completion, facilities and shallow offshore/onshore logistics.
The Hanifa and Tuwaiq Mountain formations are Jurassic in age (Figure 1) and consist of a mixed section of dark organic rich limestone beds. These formations are regionally established as the principle source rock that charged majority of the overlying Jurassic reservoirs in the region, and in Bahrain, the cretaceous reservoirs as well. These source rocks are the main targets of the recently discovered Khalij Al Bahrain (KAB) basin in Bahrain with initial resource estimates indicating potentially up to 80 billion barrels of unconventional oil and 14 trillion cubic feet of gas in place.
Location and Geological Settings
KAB basin is located in the eastern part of the Arabian basin straddling the area towards the east of Saudi Arabia, west of Qatar Arch and south of the Zagros fold belts. Majority of the basin today falls within the land bound shallow waters around the main island of Bahrain. Major fields in the area include Awali, Dukhan and Abu Safah which are likely to have been sourced from these Jurassic source rocks (Figure 2). KAB basin also lies in close proximity to the Jafurah basin which is a significant Jurassic unconventional play in Saudi Arabia targeting the same formations .
The thermal maturity of organic-rich mudstones is one of the main parameters to evaluate, when appraising a new area in an unconventional shale play project, to decide on the best field development strategy and to define the landing zones. Conventionally, thermal maturity is derived from optical vitrinite reflectance measurements, but this technique has some limitations in marine sediments with lack of terrestrial material. Other techniques, such as Rock-Eval pyrolysis, are destructive and the results can be biased if oil-based mud is used to drill the well. In this contribution, a fast, easy and non-destructive method known as Raman spectroscopy is proposed to estimate the maturity of mudstone samples from the Argentinian Vaca Muerta formation, collected from a wide range of maturities.
Raman spectroscopic measurements were executed on a variety of Vaca Muerta shale samples. A complete maturity depth profile was acquired for one well over the entire Vaca Muerta organic shale sequence. Additionally, samples from eight further wells, presenting a wide range in the expected maturity, were examined with the Raman technique. Using a correlation between the Raman spectroscopic signal and vitrinite reflectance, established earlier based on a set of reference samples, containing organic-rich mudstones from a variety of paleo-marine sedimentary basins in North America, thermal maturities were derived for the Argentinian shale samples. For certain samples kerogen was extracted and properties of the isolated kerogen were measured. The Raman results were not only compared to standard maturity indicators such as vitrinite reflectance or Rock-Eval pyrolysis, but also with other non-standard techniques like DRIFTS (Diffuse Reflectance Infrared Fourier Transform Spectroscopy) or results derived from the kerogen properties.
This case study in the Vaca Muerta shows a good correlation between the maturity values derived from the Raman measurements and maturities inferred from other methods. The depth profile shows a trend of increasing maturity with depth as expected for such a thick unconventional reservoir.
In contrast to other techniques that require isolation of kerogen, polishing of the sample surfaces, or even crushing of the samples in addition to excessive cleaning, the Raman technique utilized here was applied directly on core chips with minimal sample preparation. This non-destructive technique is fast and easy, while the accuracy is comparable to other techniques like infrared spectroscopy, kerogen skeletal density, or optical vitrinite reflectance measurements. The simplicity and accuracy of the Raman technique can provide critical information about vertical and lateral variability of thermal maturity at basin scale in a short period of time, helping to understand the burial history and its relationship with the variability of hydrocarbon properties.
The Early Tithonian – Early Valanginian Vaca Muerta Formation of the Neuquén Basin in Argentina, constitutes a world-class shale play outside the US and Canada, and corresponds to distal marine facies of the Vaca Muerta-Quintuco System. The aim of this work is to present a basin-scale characterization of the vertical and lateral distribution of the organic-rich units (TOC>2% by weight) of the Vaca Muerta Formation, integrating them within a sequence stratigraphic framework. The dataset comprises basin-scale 3D seismic coverage and almost five hundred wells widely distributed over an area of 30,000 km2. The Vaca Muerta Play includes twelve organic-rich units (OVM, Organic-rich Vaca Muerta with TOC ≥ 2% by weight), where the first eight correspond to the up-to-date tested landing zones. These OVM units correspond to transgressive systems tracts and lower section of highstand system tracts of high frequency sequences and were defined considering a well marker framework including chronostratigraphic surfaces and diachronic surfaces (top of organic-rich facies). Multiple regional well correlations were developed and calibrated with well geochemical data and acoustic impedance seismic sections. Finally, the results of this study are presented through eight thickness maps of the main organic-rich units (OVM1-OVM8) and several regional well and seismic interpreted sections. These regional maps allow us to infer stratigraphic controls (e.g. systems tracts, previous clinoform paleo-topography, etc.) and influences of regional tectonic controls (morpho-structural domains). Regional thickness maps presented in this paper allow a detailed understanding of the 3D distribution of the main landing zones of the Vaca Muerta Play in the Neuquén Basin and are very useful in exploration and development subsurface assessments. The methodologies and results in this paper are also applicable to others unconventional resources of marine shales.
The Early Tithonian – Early Valanginian Vaca Muerta Formation (Weaver, 1931, emend. Leanza, 1973) of the Neuquén Basin in Argentina, constitutes a world-class shale play outside the US and Canada. The Vaca Muerta Formation corresponds to distal marine facies (outer ramp to basinal facies in a mixed siliciclastic-carbonate setting) of the Vaca Muerta-Quintuco System.
Zhang, Hui (PetroChina) | Wang, Lizhi (Schlumberger) | Wang, Zhimin (PetroChina) | Pan, Yuanwei (Schlumberger) | Wang, Haiying (PetroChina) | Qiu, Kaibin (Schlumberger) | Liu, Xinyu (PetroChina) | Yang, Pin (Schlumberger)
Located at the foothills of Tianshan mountains, western China, the Dibei tight gas reservoir has become one of the key exploration areas in last decade because of its large gas reserve potential. The previous exploration effort yielded mixed results with large variations of the production rates from these exploration wells and many rates are too low to be deemed as discovery wells. Petrophysical properties were excluded as controlling factors because these properties for most exploration wells are very similar. Under the large tectonic stress, heterogeneous natural fracture systems are induced and unevenly distributed in the reservoir, which might be the controlling factor for production. However, due to the limitation of the seismic data quality, quantitative fracture modeling with seismic is not possible for this field. A new method predicting the 3D occurrence of the natural fractures in the reservoir is needed.
In this study, geomechanics-based methods were used to predict the natural fracture systems in the reservoir. The methods started from classification of natural fracture systems based on borehole image and core data into either fold-related and/or fault-related fractures. Geomechanics-based structure restoration was conducted to compute the deformation and the perturbed stress field from the restoration of complex geological structures through time. A correlation was established between the fold-related perturbated stress field and the occurrence of fold-related fractures from wells to predict the 3D occurrence of this type of natural fractures. Meanwhile, the computation of the perturbed stress field around 3D discontinuities (i.e. faults) for one or more tectonic events was conducted by the Boundary Element Method (BEM) until a good match was achieved between the fault-related perturbed stresses and observed fault-related fractures from the wellbore. By using the output from the two methods, the discrete fracture network (DFN) model was constructed to explicitly represent the occurrence and geometry of the natural fracture system in the reservoir in a geological model. A geomechanical model was constructed based on an integrated workflow from 1D to 3D. The fracture stability was then calculated based on the 3D geomechnical model.
Detailed analysis was conducted among the DFN model, the geological model of the reservoir and productivity of the exploration wells, and very good correlation was revealed between the productivity of the exploration wells and the occurrence and geometry of the natural fractures and the structural position of the reservoir.
This study shows that geomechanics-based methods efficiently capture the occurrence of natural fracture systems and reveal the production-controlling factors of the tight gas reservoir. It demonstrates that geomechanics is a powerful tool to support successful exploration of the tight gas reservoir in tectonically stressed environments.
Africa (Sub-Sahara) Eni has begun production from the Vandumbu field and made a new oil discovery in the Afoxé exploration prospect in Block 15/06 offshore Angola. First oil from the Vandumbu field, through the N'Goma floating production, storage, and offloading vessel, was achieved in late November, 3 months ahead of schedule. Vandumbu is approximately 350 km northwest of Luanda and 130 km west of Soyo. This, along with the startup of a subsea multiphase boosting system in early December, boosts oil production from Block 15/06 by 20,000 B/D. The rampup of Vandumbu is expected to be completed in 1Q 2019. Block 15/06 is being developed by a joint venture formed by Eni (36.84%, operator), Sonangol (36.84%), and SSI Fifteen (26.32%). Asia Pacific Ophir Energy's Paus Biru-1 exploration well in the Sampang production-sharing contract (PSC) offshore Indonesia has resulted in a gas discovery.