Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
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) 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.
Africa (Sub-Sahara) Vaalco Energy started oil production from the Etame 12-H development well offshore Gabon. The well was drilled to a measured depth of approximately 3450 m and was targeting the recently discovered lower lobe of the Gamba reservoir. It was brought on line at a rate of 2,000 BOPD with no indication of hydrogen sulfide. Vaalco (28.07%) is the operator with partners Addax Petroleum (31.63%), Sasol (27.75%), Asia Pacific KrisEnergy started drilling the Rossukon-2 exploration well on Block G6/48 in the Gulf of Thailand, using the Key Gibraltar jackup rig. The well will reach a total depth at 5,462 ft and will test Early Miocene stacked fluvial sandstones on a broad structural high.
This course will discuss the practical state-of-the-art techniques of Volume to Value (VV) to help attendees assess exploratory deepwater offshore oil and gas prospects and quantify economic values of the prospects. Attendees will learn how to develop a preliminary field development plan for a given discovery prospect and estimate oil and gas recovery, wells required, and costs. They will also learn how to conduct economic evaluation for lease sales or farm-in opportunities. Upon completion of this course, attendees should be able to evaluate the commercial potential of original oil and gas in-place in exploratory blocks and develop preliminary field development plans. Attendees should also be able to obtain value of the opportunity in order to make the decision to go ahead and develop the field or walk away from it, as well as identify constraints in terms of geology and engineering that will make it viable or impede the realization of the project.
Cornelius, Sharon (Department of Earth and Atmospheric Sciences, University of Houston, Houston, Texas) | Castagna, John P. (Department of Earth and Atmospheric Sciences, University of Houston, Houston, Texas) | Emmet, Peter A. (Department of Earth and Atmospheric Sciences, University of Houston, Houston, Texas)
Composite medium modeling of mixed salt-body mineralogies and multiple regression analysis lead to the conclusion that this velocity variation can be explained by the lithological variation within the salt, which also varies by latitude.
Brazil’s state-owned Petrobras and El Dorado, Arkansas-based Murphy Oil have agreed to combine most of their US Gulf of Mexico assets to form a joint venture (JV) that will average 75,000 BOE/D in production during the fourth quarter. Murphy Exploration & Production will serve as the JV’s operator with an 80% stake, while Petrobras America will hold 20%. The deal excludes exploration blocks from both companies, with the exception of Petrobras’ blocks that hold deep exploration rights. As part of the deal, Petrobras could receive more than $1 billion, including $900 million in cash and $150 million if price and production benchmarks are surpassed during 2019–2025. Murphy will also cover $50 million of Petrobras' costs at the Chevron-operated St. Malo Field if enhanced oil recovery projects are greenlit.
The oil and gas industry has vastly accelerated the pace of approving investments for new projects over the past 18 months. New facilities worth more than $110 billion have been approved for development since the beginning of 2017, versus only $50 billion in 2016. In May there were three major approvals: Total’s Zinia deepwater development off Angola, Cheniere’s LNG liquefaction Train 3 project at Corpus Christi, Texas, and the Santos-led Arcadia coalbed methane project in Queensland, Australia, feeding the Gladstone LNG export facilities. Momentum was maintained last week as the Norwegian parliament approved the development of Equinor’s Johan Castberg field development project in the Barents Sea, which will potentially add more than $40 billion in revenues to the Norwegian economy during the course of its production life. Higher oil prices, an improved outlook for gas demand, and lower offshore development costs are driving this rebound in the industry.
Oghena, Andrew (Chevron U.S.A. Inc.) | Zhou, Dengen (Chevron U.S.A. Inc.) | Fitzmorris, Robert (Chevron U.S.A. Inc.) | Chawathe, Adwait (Chevron U.S.A. Inc.) | Colina, Julio De La (Chevron U.S.A. Inc.) | Orribo, Jose (Chevron U.S.A. Inc.) | Gentry, Michael (Chevron U.S.A. Inc.)
Huge oil resources have been discovered in the Wilcox Trend fields of Deepwater Gulf of Mexico (GOM). The Wilcox Trend fields are ultra-high pressure and high temperature, highly undersaturated, low permeability reservoirs typically with moderate to high oil viscosities. As a result of the unfavorable rock and fluid properties coupled with anticipated large well spacing due to high well cost, the estimated primary recovery factor with artificial lift is on the order of 10 – 15%. Incremental recovery factors from water injection are forecast from 2 – 5% due to anticipated limited injectivity increasing the total oil recovery factor (primary plus secondary) to 12 – 20%. Miscible gas was thoroughly studied to determine if it could significantly increase the oil recovery factors forecast for secondary recovery.
We have carried out detailed miscible gas injection studies for six Wilcox Trend fields. Results from these field case studies demonstrate that miscible gas injection has the potential to increase the total oil recovery factor to 15 – 25% or 5 – 10% incremental above that forecast for primary depletion with artificial lift. The increase in the oil recovery from gas injection is from the improved reservoir processing rates and high local recovery efficiency of miscible displacement processes. In addition, the increase in oil recovery is due to higher oil production rates because of gas injection supporting reservoir pressure and providing natural gas lift. The GOM Wilcox field gas injection displacement process will be implemented as a secondary recovery process (before waterflood) rather than tertiary method (after waterflood).
This paper will report a new systematic workflow for integrating ultra-high pressure laboratory PVT and slim tube data and high resolution mega static earth-models into compositional reservoir simulation models for assessing gas injection displacement processes in these reservoirs. Wilcox reservoir simulation performance results will be presented for primary depletion with artificial lift, water flooding, gas injection, and gas followed by water injection and vice versa. The major uncertainties and their effect on incremental oil recovery from gas injection, resolutions to barriers to Deepwater gas injection projects, and key enabling technology developments for the ultra-high pressure miscible gas injection process will be discussed. We will end our presentation with a description of future plans for a number of GOM Deepwater Wilcox trend fields under consideration for gas injection development.