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Africa (Sub-Sahara) ExxonMobil will drill its first exploratory well offshore Liberia this month, the company announced on 18 October. A deepwater well is planned on the Liberia-13 Block, which is about 50 miles off the coast of the West African country. Liberia has no oil production at present. Solo Oil plans to spud the Ntorya-2 appraisal well in Tanzania next month. The drilling pad is a mile southwest of the 2012 Ntorya-1 discovery well, which was tested at rates of 20.1 MMcf/D of gas and 139 B/D of condensate. An independent report estimated the discovery to hold 153 Bcf of gas in place, of which 70 Bcf is considered a gross best-estimate contingent resource. A gross best estimate of more than 1 Tcf of gas in place has been made for the Ntorya prospect as a whole, in which the company has a 25% interest.
TechnipFMC and McPhy signed a memorandum of understanding (MoU) to jointly work on the development and project implementation of hydrogen technology. Separately, McPhy and Chart Industries also signed an MoU to scale up hydrogen projects across various markets. Shell's CEO said the Dutch supermajor has "too many layers" and that the move to downsize will help ensure its future. As a result, at least 9,000 people are expected to leave the oil and gas producer between now and 2022. The companies say they will expand their existing technology collaboration to create and deliver solutions to help customers, suppliers, and other businesses lower emissions. Royal Dutch Shell is looking to slash up to 40% off the cost of producing oil and gas in a major drive to save cash so it can overhaul its business and focus more on renewable energy and power markets, sources told Reuters. Phase 1 involved a feasibility study for a facility capable of capturing 750,000 tonnes of carbon dioxide annually. The next phase will explore building a facility capable of more than twice that amount.
Polo, Rosana (Oxy) | Arciniegas, Jaime (Oxy) | Valencia, Brian (Oxy) | Vulgamore, Travis (Oxy) | Nuñez, Walter (Oxy) | Ortega, Camilo (Ecopetrol) | Palisch, Terry (CARBO Ceramics) | Velez, Eduardo (CARBO Ceramics) | Tineo, Roberto (Schlumberger)
The La Cira Infantas field is located in the Middle Magdalena basin in the Santander region of central Colombia. This oil-producing development is under secondary waterflood using five-spot and inverted seven-spot patterns. The reservoir has high vertical and horizontal heterogeneity, and there was concern about effectively draining the reservoir. A new hydraulic fracturing design was deployed for the first time in Colombia (and South America) to improve drainage and surveillance.
With over 1200 producers and 500 injectors, the La Cira Infantas waterflood is well established. Waterflood surveillance indicated less-than-optimal recovery due to near-wellbore skin in the injectors and suspected poor height coverage. A novel proppant technology was incorporated into the fracture design allowing for consolidation of the proppant pack in the fracture with low bottomhole temperature and minimal stress on proppant, enabling long-term undamaged injectivity. This technology also incorporates an inert tracer into the proppant grains, which provides propped height determination after the treatment using a neutron log. This multi-faceted proppant technology was successfully deployed on one well, and additional wells are planned in 2020.
This paper will first review the background of the field development including current completion techniques, along with the challenges being faced with the waterflood recovery. It will review the self-consolidating proppant technology and show the benefits of its use in this application to promote high-conductivity fractures and minimize damage to injectivity. The companion tracer technology will be presented along with plans to perform neutron logging and identify propped fracture height. This information can be fed into fracture propagation models to determine the fracture geometry, which is then used for reservoir and waterflood surveillance analysis. The technique allows for meeting the goal to improve injectivity into both high-skin and low-permeability reservoirs.
Although this proppant technology has been used in other frac pack applications, this is one of the first case histories of the technology being used on land for improving injectivity and waterflood coverage in Colombia. This paper will be useful for reservoir and completion engineers working on waterflood fields that contain vertically and horizontally heterogeneous formations, and wish to maintain undamaged injectivity, improve waterflood sweep efficiency, and monitor the proppant pack over time.
Peng, Yingfeng (China University of Petroleum-Beijing) | Li, Yiqiang (University of Calgary) | Sarma, Hemanta K. (China University of Petroleum-Beijing) | Gao, Shenen (University of Calgary) | Kong, Debin (Research Institute of Petroleum Exploration & Development RIPED, PetroChina)
Enhancing oil recovery from thick heterogeneous carbonate reservoirs poses great challenges, be it through waterflooding or gasflooding. In this study, a three-layer 3D physical model was established based on artificial core technology and scaling criteria, taking into account the mineral composition, petrophysical properties, pore structure, wettability, heterogeneity, dynamic, bottom aquifer, interlayers, and well pattern. Experiments were carried out under circumstance of high temperature and high pressure. A numerical simulation model incorporated with local geological characteristics was built for subject well-area unit. The development process and ultimate oil recovery of conventional water injection, gas-assisted gravity drainage (GAGD), edge-bottom water injection (EBWI), and a method of combination of GAGD and EBWI proposed in this paper, named CGE were studied. For this kind of reservoirs, the experiments showed that, oil recovery of GAGD and EBWI were 40.01% and 37.11%, respectively, higher than conventional waterflooding process, while CGE had the most potential with oil recovery 43.85%. The numerical simulation showed that, oil recovery of CGE was 49.87% and the water cut was extremely low in the first 11 years. GAGD significantly increased Bond Number and had strong water control ability, but it relied on the pressure accumulation, thus there was a non-effective period. EBWI had no obvious non-effective periods, and thus enhancing oil recovery in the early stage through forced gravity displacement. CGE is a feasible and efficient combination development method, although there is still a problem of water control in the later stage. In addition to the research of EOR methods, this paper also helps broaden the means of researching carbonate reservoirs and design more schemes, based on the successful implement of the experiments.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders. Examples are provided including corporate, business unit and department case studies. Safety leadership focuses on the Human Factors (HF) which complement technical training to optimise reliability, safety, compliance, efficiency, and risks within a team-based environment. The IOGP laid down the HF skills and competencies required, and they form the basis for specialised O&G HF training's delivered by Mission Performance. This 1-day course reviews the key human factors but then also reviews what can be done to accelerate and scale operational roll-out for optimum and sustained impact, including integration with existing safety processes and (reporting) systems, refreshers, assessments, measurements, as well as the role of leadership and culture. Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion.
SPE, through its Energy4me programme, will present a free one-day energy education workshop for science teachers (grades 8–12). A variety of free instructional materials will be available to take back to the classroom. Educators will receive comprehensive, objective information about the scientific concepts of energy and its importance while discovering the world of oil and natural gas exploration and production. Energy4me is an energy educational public outreach programme that highlights how energy works in our everyday lives and promote information about career opportunities in petroleum engineering and the upstream professions. SPE’s Energy4me programme values the role teachers and energy professionals play in educating young people about the importance of energy.
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.
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. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia. Statoil Australia Theta (80%) is the operator, with partner PetroFrontier (20%).
Africa (Sub-Sahara) Oil samples have been recovered in the FAN-1 exploration well, being drilled offshore Senegal. Elevated gas and fluorescence were encountered in a shallow secondary target, and the presence of oil was confirmed by an intermediate logging program. Oil samples from thin sand were collected by a wireline formation tester for further analysis. The well will be deepened to a planned total depth of approximately 5000 m. Cairn is the operator (40%), with partners ConocoPhillips (35%), FAR (15%), and Senegalese national oil company Petrosen (10%). A drillstem test of BG Group's Mzia-3 well--located in Block 1, offshore southern Tanzania, at a water depth of around 1800 m--reached a maximum sustained flow rate of 101 MMscf/D of natural gas. The Mzia prospect is a multilayered field of Upper Cretaceous age with a gross gas column estimated at more than 300 m.
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.