PY-1 is one of the few fields in India producing hydrocarbons from Fractured Basement Reservoir. The field was developed with nine slot unmanned platform with gas exported through a 56 km 4" multiphase pipeline to landfall point at Pillaperumalnallur. Field was put on production in November 2009 with three extended reach wells. The production performance of the field had some surprise and declined earlier than expected. As a result, based on the conclusions drawn from an integrated subsurface study, a two wells reentry campaign to side track wells Mercury and Earth was planned to be executed in Q1 2018. The objectives of this paper are twofold: 1. Review the production performance of a granitic basement gas field and share learnings which may be useful for similar fields being developed elsewhere.
In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
Cai, Junjie (Shenzhen Branch, CNOOC China limited) | Wen, Huahua (Shenzhen Branch, CNOOC China limited) | Gao, Xiang (Shenzhen Branch, CNOOC China limited) | Cai, Guofu (Shenzhen Branch, CNOOC China limited) | Hu, Kun (Shenzhen Branch, CNOOC China limited)
Huizhou Depression is in the exploration peak stage at present. The main target layer is gradually extending from the middle-shallow traps to the deep paleogene traps and the shallow lithologic traps, and the difficulty of exploration is totally increased. Paleogene layer oil&gas exploration is faced with the problems of deep buried depth, reservoir heterogeneity and uncertain distribution of high-quality hydrocarbon sources.
By combining tectonic evolution analysis with sequence stratigraphy, considering regional stress background and the utilizing of the seismic facies, the main faults tectonic features, stratigraphic sedimentary characteristics, the distribution position of sedimentary center and the control effect of the palaeogeomorphology on the sedimentary distribution range deposited from the transition zone are analyzed.
It is concluded that the lower Wenchang period's tectonic movement was dominated by the southern depression control fault, and the semideep-deep lacustrine high-quality hydrocarbon source rocks were mainly distributed in the south of the Huizhou Depression, such as HZ 26 Sag and the subsag of the XJ30 Sag. The braided river delta deposited from XJ30 transfer zone is mainly distributed along the west side of the long axis of XJ30 sag, and the semideep-deep lacustrine facies mudstone is formed in the east of XJ30 Sag. In the upper Wenchang period, the activity of the depression control faults in the northwest of the Huizhou Depression becomes stronger than the south, which influences the sedimentary center migrated from southeast to the northwest. The sediment provenance of XJ30 transfer zone deposits perpendicular to the long axis of the XJ30, and the long braided river delta is formed in the south side of the XJ24 Sag. In Enping period, which is changed from strong rift phase to rift-depression transition phase, the shallow lacustrine-swamp facies are taken as the main source rocks, and shallow braided river delta is widely developed, while the sediment from the provenance of XJ30 transfer zone is weakened.
The northern and southern migration of the transfer zone provenance river delta and the northern and southern distribution characteristics of the source rocks of semideep-deep lacustrine facies are caused by the differences of the northern and southern fault activities during the Paleogene period. Through the combination of structural evolution analysis and sedimentary characteristics analysis, the analysis of paleogeomorphology's effect on the control of sedimentary system is of great importance to the identification of high-quality paleogene reservoirs and hydrocarbon sources.
The Ceduna Sub-basin is one of the few remaining frontier basins in Australia today. Few exploration wells have been drilled in the basin and none have encountered hydrocarbons. The current study aims to investigate the hydrocarbon prospectivity of an area of interest (AOI) within the distal part of the Ceduna Sub-basin, where no well information is available.
The study uses 3D seismic data and employs principles from geophysics, structural geology, sedimentology, sequence stratigraphy, and petroleum systems analysis in a comprehensive investigation to understand the Ceduna Sub-basin. Multiple 2D basin models were created for the AOI to test different scenarios in a detailed risk analysis of the petroleum system and its major controls. They were identified from a comprehensive literature review and after a thorough interpretation of the 3D seismic survey in the AOI.
Results show that the best reservoir is located within the low stand systems tract (LST) deposits of the Hammerhead Sandstone (Ss) and Top Tiger Ss. The potential source rock occurs in the condensed high stand system tract (HST) deposits in the Base Tiger Ss and White Pointer Ss. 1D modeling showed that these source rocks may have generated hydrocarbons as their depth is <9 km. The critical moment during the source rock history was at 80 Ma coinciding with the deposition of the Hammerhead Ss.
Based on the regional structural framework, faults were initiated after source rock deposition. Several growth faults may pose a risk in terms of hydrocarbon leakage. Different 2D models have advanced the understanding of the petroleum systems in the AOI. The results showed that the most prospective areas are within a rollover anticline play and those areas where intra-formational seals are present. The model confirms that fault integrity represents the prime risk across the basin.
The current study contributes to understanding of the Ceduna Sub-basin by identifying two different plays in the AOI: rollover anticline and tilted fault block. Probability analysis of the different petroleum elements shows that the rollover anticline play has the highest geological probability of success.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
Society of Petroleum Engineers - Copyright transferred to SPE by Larry Moore on behalf of Preston L. Moore.
During the previous 14 years, North American unconventional reserve delineation activities have resulted in hundreds of billions of dollars in capital spending. Development of the accompanying defined reserves has generally been a recent occurrence; in most established plays, the typical wellbore has been associated with field development rather than delineation.
Approximately 102,000 horizontal wells have been drilled and completed in North America since 1990, at an industry cost of approximately USD 750 billion. However, there is a clear trend toward continuous improvement in both process and production response. Much of the learning curve has been based on trial-and-error (T&E) activities, rather than the deliberate acceptance and integration of upfront measurements with the application of physical realities and rigorous peer-reviewed algorithms, concepts, and practices.
During the early history of hydrocarbon extraction, operators experimented with various vertical well drilling and completion (D&C) processes to maximize production and optimize net present value (NPV). Given the steep learning curve that the North American industry has experienced and the significant D&C capital cost of a single unconventional well, it is no longer prudent for national oil companies (NOCs) outside North America to repeat the pattern of historical experimentation to achieve equivalent (or better) efficiencies and results.
This paper offers a number of suggestions and concepts that can be applied to dramatically shorten the learning curve and minimize capital expenditures associated with efficient extraction of ultralow-permeability hydrocarbon reserves. North American parameters that have clearly impacted performance (parallel lateral spacing, fracture spacing along a lateral, total exposed conductive fracture surface area, decreasing proppant diameter, lateral length, etc.) are examined. The quantitative value of applying rigorous reservoir modeling, intensive study of historical practices, and upfront measurements, such as far-field fracture mapping, near-wellbore (NWB) production flow-splitting, and long-term diagnostic shut-in testing, is then estimated by examining the cost of error in delineating and developing a given acreage position.
The focus of this study is to improve our technical understanding of anticipated drilling hazards in the Arctic Circle, especially hazards relating to drilling into and adjacent to evaporitic (salt) structures and associated tectonics. We explore current drilling technologies available to us to mitigate any anticipated drilling hazard. We demonstrate applicable operational experiences from other areas similar to drilling in the Arctic.
The Arctic's vast oil and gas potential has spurred exploration since mid-20th century. Government institutions such as the Geological Survey of Canada and historic companies such as Panarctic provide critical information on geology and petroleum discoveries. U.S. Geological Survey (2008) published Arctic mean estimated undiscovered technically recoverable conventional oil and gas resources at a total of 412 billion barrels of oil equivalent (BBOE).
Exploration in the Arctic varies in complexity mainly based on the depth drilled and hazards encountered. The remoteness of drilling anywhere in the Arctic makes both onshore and offshore operations generally more complex than drilling elsewhere in the world. To put it in perspective, our research into drilling time in deepwater Nova Scotia show for the majority of high complexity wells, non-productive time (NPT) can exceed 24% of total drilling time, and half of documented NPT is contributed to formation related problems.
Our geological analysis has found that Arctic petroleum basins and margins such as the Sverdrup Basin and East Canada and show comparable salt tectonics to Nova Scotian continental margin, offshore Brazil and Angola. Salt diapirs, salt domes, and thicken salt sections are common occurrences. Associate structures such as anticlines, extensional growth faults, wrench faults are observed in these basins. Extensional growth faults, listric normal faults, thrust faults, flank-salt shears, and brecciated fault zones are associated with salt bodies. These structures are planes of weakness. Depending on effective in-situ stress conditions these faults and intense natural fractures can become critically stressed and induce slip on plane.
Salt rheology and geochemistry pose higher drilling risk than drilling through other rocks. Salt creeps towards borehole during drilling, and plastic yielding around borehole is unavoidable when drilling through salt body. Boundary zone tends to be heavily naturally fractured, brecciated, or sheared, and rock may become unconsolidated and lose its cohesiveness. Taking heavy losses in naturally fractured boundary zone may occur. Abnormal pressure exists and taking a kick while drilling out of salt body is not uncommon.
Public domain documentation available for Arctic region support the hazards identified by our geological analysis and also suggest that a great deal of downhole uncertainty exists during early exploration. In analogous setting outside of the Arctic Circle, drilling problems related to pressure uncertainty, tight windows and wellbore stability are referenced throughout and the lessons learned suggest limiting the uncertainty when possible and the use of contingency planning.
Based on the similarities in the structural geometry of petroleum basin in Arctic and select basins in other parts of the world, it seems logical that lessons learned from these areas away from the Arctic, e.g., offshore Nova Scotia, Brazil, and Angola should provide some assistance with the planning and execution of Arctic drilling activities.
All information collection during this study has been referenced throughout. This information will be beneficial for continued support of drilling in salt tectonic structural provinces in the Arctic and anywhere else in the world.
Keong, Ong Swee (PETRONAS Carigali Sdn. Bhd.) | Bt. Abdullah, Azirul Liana (PETRONAS Carigali Sdn. Bhd.) | Bin Ahmad Fuad, Ahmad Syahir (PETRONAS Carigali Sdn. Bhd.) | Bt Hamdan, Norazean (PETRONAS Carigali Sdn. Bhd.) | Bt Anuar, Azlina (PETRONAS Carigali Sdn. Bhd.) | Basu, Debnath (Schlumberger) | Ysaccis, Raul (Schlumberger) | Murthy, K S (Schlumberger) | Kim, Taesoo (Schlumberger)
The study area is situated in the offshore West Nile Delta basin towards the northeast of Alexandria, Egypt. This is a major petroleum habitat hosting many gas and condensate fields. The present paper summarizes the petroleum system elements for hydrocarbon prospecting in the Messinian and deeper stratigraphic section based on an integrated study of seismic and well data.
Mixed well results have been observed in the area with proven gas fields found in stratigraphic fluvial channels in the Messinian. Rotated fault blocks and fault dependent traps were tested but no discoveries were proven. Failure could be due to trap integrity issues and inadequate migration pathways. Potential remaining stratigraphic plays identified are deepwater slope channels in the pre-Messinian to Oligocene section similar to overlying Pliocene gas fields.
Depositional models based on seismic attribute mapping and a few wells generally depicts a NW-SE facies belt trend dominated by deepwater slope channel complexes flanked by slope shales ranging in age from Upper Oligocene to Miocene (Pre-Messinian). In the Messinian, the depositional environment is associated with a major sea-level drop with consequent exposure of the shelf/slope. It contains predominantly incised valleys and fluvial-fills flanked by interfluves.
The hydrocarbon charge is expected from Cretaceous-Jurassic and Early Tertiary pro-delta shale source rocks (Marten et al., 2004). Evidence of highly mature thermogenic gases (2.0 % - 2.5% VRo) advocates the assumption of the presence of a deeper source rock contribution from limited well calibration. Basin modeling results shows that the modelled source rocks are presently in the hydrocarbon generation window. Source rock generation has occurred very late from 9.0Ma to 1.0Ma and migration timing post-dates trap formation. Traps are expected to be charged vertically and through fault conduits as observed in well results.
This study paved the way for a better understanding of the petroleum system elements which consequently forms the basis in risking the Messinian and deeper exploration plays and shows that the Messinian stratigraphic channel plays are most prospective.