Africa (Sub-Sahara) An initial drillstem test on the Mzia-2 well in Block 1 flowed at a maximum rate of 57 million ft3 of gas per day, increasing the estimated recoverable resources from the field to 4.5 trillion ft3. This is the first test carried out on a Cretaceous discovery in deepwater offshore Tanzania. BG (60%) is the operator in partnership with Ophir Energy (40%). Asia Pacific Production has begun from the Wei Zhou 6-12 oil field in the Beibu Gulf basin in the north part of the South China Sea. The project has 10 producing wells drilled at an average water depth of 29.2 m. CNOOC has a 51% operating interest in partnership with Roc Oil, Horizon Oil, and Oil Australia. Salamander Energy signed production-sharing contracts for the Northeast Bangkanai and West Bangkanai license areas, onshore central Kalimantan in Indonesia. Each area covers approximately 2,214 sq miles.

Africa (Sub-Sahara) Sahara Group discovered hydrocarbons in three wells drilled in Block OPL 274, located onshore in Nigeria's Edo State. Olugei-1 was drilled to a measured depth of 4537 m and encountered five hydrocarbon zones, with 33 m of net pay. Oki-Oziengbe South 4 was drilled to a measured depth of 3816 m and encountered 64.3 m of net pay in 13 hydrocarbon-bearing zones. Oki-Oziengbe South 5 was drilled to a measured depth of 3923 m and encountered 91 m of net pay in 19 reservoirs. Sahara Group (100%) is the operator. Asia Pacific Sino Gas & Energy Holdings (SGE) flowed gas (coalbed methane) from its first horizontal well in the Linxing production sharing contract (PSC) in China's Shanxi province.

Africa (Sub-Sahara) The drillship Ocean Rig Athena is preparing to drill appraisal and exploration wells offshore Senegal for a joint venture (JV) led by Cairn Energy. Two wells will appraise the SNE discovery, which was ranked by IHS CERA as the world's largest for oil last year. An exploration well will also be drilled in the Bellatrix prospect, for which mapping has indicated a potential 168 million bbl of oil resources. Cairn holds a 40% interest in the JV, with remaining interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%). The Ksiri West-A exploration well drilled by Circle Oil on the Sebou permit onshore Morocco has flowed gas at a rate of 8 MMcf/D following tests. It is being readied for production.

Asia Pacific Santos discovered gas with the Corvus-2 well in the Carnarvon Basin, offshore Western Australia. The well, located in permit WA-45-R, in which Santos has a 100% interest, reached a total depth of 3998 m. It intersected a gross interval of 638 m, one of the largest columns discovered across the North West Shelf. Wireline logging to date has confirmed 245 m of net hydrocarbon pay across the target reservoirs. Total SA and partners ExxonMobil and Oil Search have signed a gas agreement with the government of Papua New Guinea that defines the fiscal framework for the Papua LNG project in the country's Eastern Highlands. The plan involves construction of three 2.7-mtpa LNG trains on the existing PNG-LNG plant site at Caution Bay just west of Port Moresby. Total has 31.1% interest, ExxonMobil has 28.3% interest, and Oil Search has 17.7%.

After receiving several unsolicited inquiries from potential buyers, Chevron said it is looking to sell its 16.7% stake in Australia's A$34 billion ($23.3 billion) North West Shelf (NWS) LNG joint venture. The NWS project has been operating for 35 years and supplies oil and gas to Australian and international markets from offshore gas, oil, and condensate fields in the Carnarvon Basin, off the northwest coast of Australia. It is also the largest producer of domestic gas for western Australia. Operated by co-owner Woodside, other partners in the JV include BHP, BP, Japan Australia LNG, and Shell. "Chevron is continuing to high-grade its portfolio, and putting its 16.7% stake in the NWS up for sale makes a lot of sense,” said Wood Mackenzie senior analyst David Low. “We see the NWS facility coming off full production this year, and going forward it will need third-party gas to keep the plant full.”

An anticipated acceleration in LNG's commoditization, driven by factors such as increased natural gas demand and newfound confidence in its potential as a marine fuel and as the cleanest of the fossil fuels, having lower emissions than either coal or oil fired power generation is expected to hand it a much larger role in global energy markets. The deployment floating liquefied natural gas (FLNG) facilities, becomes increasingly important as an option to achieve this task rather than an onshore facility. Jettyless LNG transfer concept could cut total project cost by 50%.

Recent policies in Europe have encouraged the use of renewables, with gas being the obvious complementary source of energy for power generation when these intermittent sources need backup power. A supply chain is the network of LNG from the upstream to the downstream called a distribution channel have three main flows which are the product, information and the finances flow. FLNG is an emerging technology for such fast and cost effective development of technology to unlock smaller, remote or environmentally sensitive fields. LNG Monetization will be thoroughly examined. FLNG however present some novel challenges less on the technical side and more to do with the supply chain, project management, stakeholder engagement, financing, regulation and tax. Understanding regulatory, legal, financing tax issues and engaging with the relevant stakeholders well ahead of investment decisions are keys. Flexibility is also being introduced in LNG Import Terminals, which have the potential to serve as a LNG Hub where LNG is received in bulk volumes from an LNG carrier and is then distributed out through gas pipeline. This solution is applicable when the visiting LNG carrier is connected to the onshore storage without a jetty. This solution enables small-scale LNG transfers to the LNG storage on shore or to the landlocked Floating Storage and Regasification Units. The international natural gas sector was geographically divided into distinct regional markets. The US and Europe supplied mainly by pipelines and Asia supplied by LNG. For all regions, there is a striking difference between the geopolitical context of international pipeline gas business and LNG which will be detailed in this work. The FSRU is lower in cost and can be reused while the land based terminals cannot be relocated. Geopolitics is a central concern for the oil and gas sector and can be viewed as a source of both risk and opportunity as identified by EY. Collaboration in adding values to the LNG business measured by total revenue will be examined in the work.

Summary

In subsea environments, using large-bore/high-rate well designs is often a key contributor to the economic recovery of hydrocarbon resources. Their use is a necessity for accommodating the huge production capacity of the reservoirs they penetrate, with the major benefit of minimizing the number of wells necessary to develop a subsea field. The enthusiasm for using such well designs, however, must also be tempered by a clear understanding of the considerable well control risk they introduce—that risk being an increased level of difficulty in bringing such a well under control if a blowout were to occur. It is common that multiple relief wells, with their inherent complexities and time investment, would be simultaneously required to bring a big-bore blowout under control. The discussion of this fact is, though, not a common topic in industry literature. Instead, capping stacks have been more the focus. Much recent attention has been trained on ensuring that capping stacks are a viable method for quickly responding to a high-rate subsea blowout. This makes sense in light of the simpler, and publicly more palatable, concept of rapidly installing a capping stack on a blown-out subsea well. Still, a capping stack is only as reliable as the wellhead it must connect to. It is because subsea wellheads have such a high chance of being damaged during a blowout that relief wells will always be relied on as the ultimate backstop for ensuring that a subsea blowout can be brought under control.

This reliance on relief wells, as they are traditionally envisioned, has limitations though when addressing a high-rate subsea blowout. Any subsea relief well will have inherent limitations resulting from the architecture of choke and kill lines (flow restrictions) and that of the crossover piping at the blowout preventer (BOP; erosion concerns). In the world of high-rate subsea blowouts, these limitations can sometimes translate into multiple relief wells being required to inject fluid at the rates necessary to affect a dynamic kill. However, the simultaneous use of multiple subsea relief wells to dynamically kill a single blowout has only been tried once in the industry’s history. As a result, some countries require that stopping a blowout must be possible by drilling only one relief well.

In this paper, we describe methods that can be implemented to transcend traditional relief well limitations via using a relief well injection spool (RWIS), with the ultimate goal of dynamically killing a subsea big-bore blowout using a single relief well. The technique varies with water depth. In both shallow-water (826 ft) and deepwater (8,260 ft) environments, the techniques are presented and analyzed that will allow using a single subsea relief well to perform a dynamic kill using 15 lbm/gal drilling fluid injected at 238 bbl/min. This particularly severe scenario, based on a big-bore gas well development in Western Australia, is chosen so that our results will have applicability to most subsea well control events that might arise in the future.

Summary A thermodynamic mineral model, based on the sulfidation of iron (Fe)-chlorite to pyrite and hydrogen sulfide (H 2 S), has been developed for predicting the concentration of H 2 S (0 to 50 ppm) in hydrocarbon-bearing clastic reservoirs. The model replaces decades-old correlations used for H 2 S prediction in clastic reservoirs globally. This study established that the primary control on f H 2 S in the subsurface is temperature and reservoir redox state, represented by the oxygen fugacity (fO 2). This discovery represents a fundamental advance in our understanding of the controls of H 2 S stability in subsurface formations and presents a thermodynamic basis for quantitative prediction of the concentration of H 2 S in clastic hydrocarbon-bearing reservoirs. The modeled fO 2 is used as one of the inputs to the pyrite-chlorite-H 2 S mineral model. The veracity of this mineral-based model has been demonstrated for pressures of 20,000 þ psi (137.9 þ MPa) and temperatures of 225 C. The model predicts f H 2 S and can be used to estimate the partial pressure and concentration of H 2 S in both liquid and gaseous hydrocarbons, vent clouds, and coexisting aqueous phase [i.e., H 2 S (aq) ]. H 2 S fugacity coefficients may be estimated at any pressure and temperature and must account for the fluid type and composition. Results from the new model are robust and consistent with measured H 2 S data from dry gas, oil, and retrograde gas condensate containing up to 10 mol% CO 2. We demonstrate for our global H 2 S data set (n ¼ 97) a 1:1 comparison between measured concentrations of H 2 S and model estimates based on our new thermodynamic mineral model. In most cases, the model can reproduce reported H 2 S values to within 63 ppm. Sensitivity analyses of input parameters, that is, pressure, temperature, salinity (a H2 O), and chlorite composition (X Fe in Fe-chlorite), are evaluated using Monte Carlo simulation. Tornado plots generated by the Monte Carlo simulations showed that estimated concentrations of H 2 S are generally insensitive to uncertainties in pressure (61,000 psi), Fe-chlorite composition (X Fe ¼ 0.65 6 0.15), and salinity (a H2 O ¼ 0.93 6 0.05).

In subsea environments, the use of larger-bore/higher-rate well designs is often a key contributor to the economic recovery of hydrocarbon resources. Their use is a necessity for accommodating the huge production capacity of the reservoirs they penetrate, with the major benefit of minimizing the number of wells necessary to develop a subsea field. The enthusiasm for using such well designs, however, must also be tempered by a clear understanding of the considerable well control risk they introduce - that risk being an increased level of difficulty in bringing such a well under control if a blowout were to occur. It is not uncommon that multiple relief wells would be simultaneously required to bring a big-bore blowout under control. The discussion of this fact is, though, not a common topic in industry literature. Instead, capping stacks have been more the focus. Much recent attention has been trained on ensuring that capping stacks are a viable method for quickly responding to a high-rate subsea blowout. This makes sense in light of the simpler, and publicly more palatable, concept of rapidly installing a capping stack on a blown-out subsea well, relative to the less-desired complexities and significant time investment of drilling relief wells. Still, a capping stack is only as reliable as the wellhead it must connect to. It is because subsea wellheads have such a high chance of being damaged during a blowout that relief wells will always be relied on as the ultimate backstop for ensuring that a subsea blowout can be brought under control.

This reliance on relief wells, as they are traditionally envisioned, has limitations though when addressing a high-rate subsea blowout. Any subsea relief well will have inherent limitations resulting from the architecture of choke and kill lines (flow restrictions) and that of the cross-over piping at the BOP (erosion concerns). In the world of high-rate subsea blowouts, these limitations can sometimes translate into multiple relief wells being required to inject fluid at the rates necessary to effect a dynamic kill. But, the simultaneous use of multiple subsea relief wells to dynamically kill a single blowout has only been tried once in the industry's history. As a result, some countries require that stopping a blowout must be possible by drilling only one relief well.

This paper describes methods that can be implemented to transcend traditional relief well limitations via the use of a relief well injection spool (RWIS), with the ultimate goal of dynamically killing a subsea big-bore blowout using a single relief well. The technique varies with water depth. In both shallow- (826 ft) and deep-water (8260 ft) environments, techniques are presented and analyzed that will allow using a single subsea relief well to perform a dynamic kill using 15 lbm/gal drilling fluid injected at 238 bbl/min. This particularly severe scenario, based on a big-bore gas well development in Western Australia, is chosen so that our results will have applicability to most sub-sea well control events that might arise in the future.

There is an increasing need to understand the influence of faults in both gas production performance and the resulting potential impact on adjacent groundwater resources.Faults can exhibit a wide variety of hydraulic properties. Where resource development induces changes in pore pressure, the effective stress and thus the permeability can be transient. In this study, w explored strategies for characterizing fault zone properties for the initial purpose of evaluating gas production performance. The same fault characterization can then be incorporated into regional groundwater flow models to more accurately represent stress, strain and the resulting transmissivities when assessing the impact of gas development on adjacent aquifers.

Conventional fault zone analysis (juxtaposition, fault gouge or shale smear, fault reactivation) is combined with hydrodynamic analysis (distribution of hydraulic head and hydrochemistry) and surface water hydrology and hydrochemistry to evaluate across fault or up fault locations of enhanced hydraulic conductivity at specific locations of complex fault systems.

The locations of identified vertical hydraulic communication from the hydraulic analysis are compared with the fault zone architecture derived from the 3D seismic volume overlain with the in-situ stress characterization. This provides an independent method of assessing other potential hydraulic communication locations based on seismic alone where no other hydraulic or hydrochemical information is available. A groundwater model is used in an inverse approach to assess the hydraulic properties required to generate observed hydrochemical anomalies so that a realistic range of rock properties can be assigned throughout the geological model to other faults. We use a case study example of the Gloucester Basin in New South Wales in eastern Australia to demonstrate how some of these techniques can be applied. The Gloucester Basin has been subject to exploration of coal seam gas with some pilot testing but no commercial production. It also contains data from groundwater monitoring bores and surface water features. The methodologies described can be applied elsewhere when faults play a key role in determining gas production performance or characterisation of groundwater flow system hydraulics in gas development areas.