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. Lingshui 17-2 encountered a gas reservoir with a total thickness of approximately 55 m. Statoil Australia Theta has drilled and completed the Oz-Alpha 1 exploration well in the southern Georgina basin in the Northern Territory, Australia.
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. 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%). Philippines National Oil Company (PNOC) has begun drilling operations on its Baragatan-1 exploration well on service contract 63, offshore Palawan Island, west of the Philippines, using the Naga 5 jackup rig.
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) 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) Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D.
Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).
The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.
This paper presents the development and implementation of a production and power optimization system supported by a nodal analysis simulation tool and an updated and calibrated multiphase flow hydraulic model.
The workflow implemented in Castilla field identifies operating conditions that may affect the performance of 577 production wells configured in a complex gathering system, managing multiphase flow for heavy oil with low gas oil ratio and high water cut. Initially, this involves the development of a tool for the systematic data transfer from official databases to the simulation model. Furthermore, the hydraulic model was calibrated to reproduce operating conditions. And once the main nodes and boundary conditions at reservoir, wells, network and processing facility were defined, various optimization scenarios were simulated.
With this workflow the field engineers are capable to propose operating changes to increase production taking into consideration network bottlenecks, power consumption, and facilities limitations. The wells with electrical submersible pumps were ranked into the following categories: pump speed variation, well redesign, surface facilities improvement and drawdown limitation. As a result, actions to be implemented in each well were defined. First, ‘pump speed variation’ classified wells quickly demonstrated how the production and power optimization procedure benefit the field. Specifically, it was possible to optimize the extraction process by increasing the oil production up to 10% using power efficiently. Second, several bottlenecks on the network were identified finding atypical pressure drops, using traditional nodal analysis for pressure, temperatures, velocities, and liquid rates calculation per node. Some of them are related to mechanical configuration and others gas accumulation in pipelines. Third, according to the simulation results, a considerable amount of production can be gained and power consumption can be reduced if these conditions are solved.
This workflow contributes to optimize power consumption and enables faster decision-making to efficiently meet the production targets by increasing oil production and reducing water/oil and power/oil ratios.
CEPSA Colombia developed an improved technique for bioremediation; implemented since 2012 in the onshore Caracara field. This optimizes the processes of biostimulation and bioaugmentation by introducing exogenous bacteria, with efficiency (reduction of grease and oil) close to 90%.
The technique exceeds the performance of other published methods, as it has been used successfully for the biotreatment of soils and fluids impregnated with hydrocarbons at concentrations of fats and oil of up to 20 ± 2 wt%, equivalent to 200,000 ± 20,000 ppm (mg carbon/kg soil). Previous studies have suggested that oily sludges only with concentrations of fats and oils below approximately half that level can be bioremediated to achieve a compliance criterion standard close to 1 wt% as established in Chapter III of Louisiana Protocol 29-B and commonly adopted as an oil industry norm.
It is an ‘ex situ’ process since although applied at the field location the sludge is first collected and stored prior to batch biotreatment. The technique is most applicable to oily sludges that do not have an excessive asphaltene and resins content: asphaltenes are not biodegradable by microorganisms, given their structural complexity and resistance to the enzymatic attack produced by bacteria.
Our successful field pilot has been expanded to an industrial scale and has over a six-year period effectively treated the environmental liability of sludge ponds of approximately 12,000 m3 inherited when CEPSA assumed its interest in the Caracara field. Operations continue, treating ongoing generation of oily waste at an estimated cost saving of 54% relative to the treatment and transport costs of contracting an external bioremediation service provider.
We have developed simple criteria to screen the suitability of oily sludges for our process, which is simple, easy to implement and cost-effective, as it relies on bacteria generated from waste products readily available in the field at no cost. It should be applicable to other fields with similar environmental conditions.
There is not enough experience of hydraulic fracturing on unconsolidated low-temperature shallow formations, similar to the main development site of the East Messoyakhskoye field - PK1-3, was found in Russia. Test fracturing was performed on directional and vertical wells in the pilot works in 2017 and the main conclusions were drawn:
Approve technological capability of hydraulic fracturing on unconsolidated and high-permeability heavy oil reservoir
Approve creating traditional vertical fracture by geophysical methods and by the results of production
Value of fracture height by different methods of mapping fracture geometry are semi-comparable, which makes it possible to estimate the averaged value of each parameter
Performed complex of geophysics logging allows to estimate in technological efficiency of hydraulic fracturing
Performed complex of laboratory studies of various chemical compound hydraulic fracturing fluids on the core material made it possible to select the optimal compound with minimal negative impact on the formation
Step-by-step method increase of the aggressiveness of the treatment designs allowed the accident-free implementation of pilot works and estimate of possible aggressiveness to tip screen out (TSO)
The productivity gains resulting from the development and operation of the wells after the fracturing allow to adapt the result to the MHF in horizontal wells with the expected productivity gain of 40%
Limite fracture height growth is achieved by planning the optimal injection design, but it is not always possible. If gas-oil contact is near, it is difficult to control the geometry of the fracture, which led to the limitation of replicating the fracturing in water-oil zones without gas cap.
Mullins, Oliver C. (Schlumberger) | Forsythe, Julia C. (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Wilkinson, Tim (TALOS) | Winkelman, Ben (TALOS) | Mishra, Vinay K. (Schlumberger) | Canas, Jesus A. (Schlumberger) | Chen, Li (Schlumberger) | Jackson, Richard (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Kauerauf, Armin (Schlumberger) | Peters, Ken E. (Schlumberger)
Downhole fluid analysis (DFA) accurately measures light absorption (optical density or OD) in different optical wavelength channels vertically and laterally in reservoirs providing accurate fluid gradients especially for dissolved gas, liquids and dissolved solids, the asphaltenes. DFA data can then be used for thermodynamic analysis using the cubic equation of state for gas-liquid equilibria, and the Flory-Huggins-Zuo equation of state (FHZ EoS) for solution-asphaltene equilibria. Thermodynamically equilibrated reservoir asphaltenes imply reservoir connectivity. Disequilibrium can imply recent or ongoing reservoir fluid geodynamic (RFG) processes, which impact major production concerns. Compositional analysis of the reservoir fluids using conventional gas chromatography (GC) and two-dimensional gas chromatography (GC×GC) can be used to validate the thermodynamic analyses, especially within a geochemical context.
Several reservoirs are examined here with DFA, GC and GC×GC methods exploring many different reservoir concerns. Connectivity and its inverse compartmentalization are recurring concerns and are effectively addressed. GC×GC is shown to support simple thermodynamic modeling enabling connectivity analysis, which is then validated in production. Viscosity profiles throughout reservoirs are accounted for using simple modeling of asphaltene gradients. Biodegradation is shown to yield three endmember viscosity profiles, no in-reservoir gradients versus large in-reservoir gradients at the OWC or large gradients at the top of the oil column, and the governing RFG processes are clearly identified. Water washing is measured over a large range and has a secondary effect on oil quality; factors that control the extent of water washing are shown. A universal protocol is used for reservoir evaluation that elucidates key reservoir concerns efficiently. This protocol is generally applicable for reservoirs in all stages of exploration, appraisal and development.