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Africa (Sub-Sahara) Aminex Petroleum Egypt (APE), a subsidiary of UK-based Aminex, discovered oil at its South Malak-2 (SM2) well on the West Esh el Mellaha-2 concession in Egypt. Tests showed flow rates of approximately 430 B/D of 40 API gravity crude oil. Based on the findings at SM2, a full field development program will be presented to the Egyptian authorities and the joint venture partners before commercial development. APE is the operator of the license with partner Groundstar Resources. Foxtrot International discovered oil and gas at its Marlin North-1 well in Block CI-27, offshore Cote d'Ivoire. A 22-m perforated section of a gas-bearing column in a Turonian interval flowed at a stabilized rate of 25 MMcf/D of gas and 150 B/D of condensate through a 46/64-in.
Africa (Sub-Sahara) ExxonMobil subsidiary Esso Exploration Angola has started oil production at the Kizomba Satellites Phase 2 project offshore Angola. The project involves the development of subsea infrastructure for the Kakocha, Bavuca, and Mondo South fields. Mondo South is the first field to begin production, and the other two satellite fields will follow later this year. The goal is to increase Block 15's production to 350,000 BOPD. Esso (40%) is the operator with BP Exploration Angola (26.67%), Kosmos Energy discovered gas at the Tortue West prospect in Block C-8 offshore Mauritania.
Africa (Sub-Sahara) Chevron has begun oil and gas production from the Lianzi Field, a subsea project in 3,000 ft of water that is expected to achieve production of 40,000 BOPD. Situated in a unitized zone between Congo and Angola, Lianzi is the first cross-border offshore oil development in Central Africa. A 27-mile electrically heated subsea production flowline is the industry's first at this depth. Chevron is the operator with a 31.25% The field partners include Total(26.75%), Eni discovered gas and condensate in the Nkala Marine prospect offshore Congo. The discovery could hold from 250 MMBOE to 350 million MMBOE in place, the company said.
Africa (Sub-Sahara) Total reported a natural-gas-condensate discovery on Block 11B/12B in the Outeniqua basin, 175 km offshore southern South Africa. The Brulpadda well encountered 57 m of net gas condensate pay in Lower Cretaceous reservoirs. Following success at the main objective, the well was deepened to a final depth of 3633 m. Partners are Qatar Petroleum with 25%, Canadian Natural Resources with 20%, and Main Street, a South African consortium, with 10%. According to consultant Westwood Energy, the Brulpadda discovery is the first frontier basin opener since ExxonMobil's Stabroek block discovery offshore Guyana in 2015. Panoro Energy said a new review by Netherland, Sewell & Associates has upgraded recoverable oil resources from the Tortue field in the Dussafu exclusive exploitation area offshore Gabon. Following a successful development drilling campaign last year at Tortue, contingent resources from the western flank of the field have been recategorized as reserves, raising proven plus probable reserves to 35.1 million bbl.
Africa (Sub-Sahara) Eni discovered gas and condensate in the Nkala Marine prospect offshore Congo. The discovery could hold from 250 MMBOE to 350 million MMBOE in place, the company said. In a production test, the Nkala Marine 1 discovery well in the Marine XII block yielded more than 10 MMcf/D of gas and condensate. Eni is the operator with a 65% interest in the block. The remaining shares are held by New Age (25%) and Societé Nationale des Pétroles du Congo (SNPC) (10%). Sonangol and Total will break ground on a deepwater oil pumping project that will increase Angola's production by more than 30,000 B/D. Four multiphase, high-pressure subsea pumps will be installed at the Rosa field in Angola Block 17 that will enable the recovery of an additional 42 million bbl, Sonangol said.
SDX Energy has made two discoveries in Egypt. The Rabul 4 well in West Gharib Concession, drilled to a 5,250-ft total depth, encountered about 43 ft of net heavy oil pay in the Yusr and Bakr formations. The discovery is under evaluation, after which the company expects to complete the well as a producer and connect it to central processing facilities at Meseda. SDX holds a 50% interest in the concession and is joint operator with Dublin Petroleum. SDX also discovered natural gas at the company-operated Ibn Yunus-1X exploration well at South Disouq.
The initial water saturation in a reservoir is important for both hydrocarbon volume estimation and distribution of multi-phase flow properties such as relative permeability. Often, a practical reservoir engineering approach is to relate relative permeability to flow property regions by binning of the initial water saturation. The rationale behind this approach is that initial water saturation is related to both the pore-throat radius distribution and the wettability of the rock, both of which impact relative permeability. However, pore-throat radius and wettability are usually not explicitly included in geomodel property modelling. Therefore, the saturation height model (SHM) should not only capture an average hydrocarbon pore volume (HCPV), but also reflect the underlying mechanisms from hydrocarbon migration history and its impact on initial water saturation distribution.
This work defines a new terminology, "excess water", for more precise classification of SHM-scenarios in reservoirs where multiple mechanisms have interacted and caused a complex water saturation distribution. The physical basis for drainage and imbibition transition zones connected to both regional and perched aquifers is given. The distribution of initial water saturation in reservoirs containing excess water is demonstrated through numerical modelling of oil migration over millions of years.
High permeable reservoirs are more likely to have locally trapped water due to lower capillary forces. A static situation occurs in areas where the capillary forces cannot maintain a high enough water saturation for further water drainage. On the other hand, both high and low permeability reservoirs may have significant excess water due to still ongoing dynamical effects. In both cases, long distances for water to drain laterally to a regional aquifer enhances the possibility for a dynamic excess water situation.
The impact of excess water on well test results are demonstrated with focus on calculation of the product of permeability and sand thickness.
Any reservoir simulator consists of n m equations for each of N active gridblocks comprising the reservoir. These equations represent conservation of mass of each of n components in each gridblock over a timestep Δt from tn to tn 1. The first n (primary) equations simply express conservation of mass for each of n components such as oil, gas, methane, CO2, and water, denoted by subscript I 1,2,…, n. In the thermal case, one of the "components" is energy and its equation expresses conservation of energy. An additional m (secondary or constraint) equations express constraints such as equal fugacities of each component in all phases where it is present, and the volume balance Sw So Sg Ssolid 1.0, where S solid represents any immobile phase such as precipitated solid salt or coke. There must be n m variables (unknowns) corresponding to these n m equations. For example, consider the isothermal, three-phase, compositional case with all components present in all three phases. There are m 2n 1 ...
Reamers are an integral part of deepwater Gulf of Mexico (GOM) drilling and their performance significantly impacts the economics of well construction. This paper presents a novel programmatic approach to model rate of penetration (ROP) for reamers and improve drilling efficiency. Three field implementations demonstrate value added by the reamer drilling optimization (RDO) methodology.
Facilitated by user interface panels, the RDO workflow consists of surface and downhole drilling data filtering and visualization, detection of rock formation boundaries, frictional torque (FTRQ) and aggressiveness estimation, ROP modeling with analytical equations and machine learning (ML) algorithms [regression, random forests, support vector machines (SVMs), and neural networks], and optimization of drilling parameters. ROP model coefficients and bit and reamer aggressiveness are dependent on lithology and computed from offset well data. Subsequently, when planning a nearby well, bottomhole assembly (BHA) designs are evaluated on the basis of drilling performance and weight and torque distributions between cutting structures to avoid early reamer wear and dysfunctions. Geometric programming establishes optimal drilling parameter roadmaps according to operational limits, downhole tool ratings, rig equipment power constraints, and adequate hole cleaning.
Separate ROP models are trained for reamer-controlled and bit-controlled ROP zones, defined by the proportion of surface weight on bit (WOB) applied at the reamer, in every rock formation. This novel concept enables ROP prediction with the appropriate model for each well segment depending on which cutting structure limits drilling speed. In the first of the three RDO applications with field data from deepwater GOM wells, optimal bit-reamer distances are determined by analyzing reamer weight load in uniform salt sections. Next, ROP modeling for the addition or removal of a reamer from the BHA is used in contrasting well designs to conceivably alleviate a USD 16 million casing inventory surplus. Finally, active optimization constraints are investigated to reveal drilling performance limiters, justifying equipment upgrades for a future deepwater GOM well.
The proposed innovative workflow and methodology apply to any drilling optimization scenario. They benefit the practicing engineer interested in drilling performance optimization by providing insights on how different cutting structure sizes affect ROP behavior and ultimately aiding in the selection of appropriate bit and reamer diameters and optimal operational parameters.
Summary In this study, an oil-in-water nanoemulsion for the effective removal of an oil-based drilling fluid has been developed by means of the phase-inversion concentration method. The influence of four factors on the droplet size and removal efficiency were tested, including the mass ratio of mixed surfactants (R m), the surfactant/oil ratio (SOR), the mass concentration of cosurfactant (c co), and the salinity of the saline solution (c s). Considering the application environment of displacement spacers, the long-term stability and temperature resistance were investigated. The results showed that R m and SOR had an obvious influence on the removal efficiency and droplet size of nanoemulsions. Because of the synergy effect of the surfactants, the nanoemulsion possesses remarkable storage stability and temperature resistance. Moreover, the removal mechanisms of the nanoemulsion were analyzed by the dynamic interfacial tension (IFT), dynamic wetting angle, and solubilization tests. The results indicated that the nanoemulsion could spread rapidly and thoroughly on the oil-wetting surfaces, and the nanoemulsion can contain more oil while the system is still stable, which is beneficial for the removal of an oil-based drilling fluid. Introduction With the continuous growth of energy demand and the development of oil and gas exploration technology, unconventional resources become a realistic alternative to traditional energy sources (Rui et al. 2018). Oil-based drilling fluid has become one of the important technical means for well drilling of unconventional oil and gas resources, such as shale-oil gas and deep-oil gas. As known, it is crucial to develop excellent cementing to achieve zonal isolation. The cementing is implemented by pumping a cement slurry into the annular space between the formation and casing to displace the drilling fluid and fill up the entire space. However, the oil-based drilling fluid can leave a thin oil residue layer on the formation and casing during the displacement by the cement slurry.