This paper presents the technical development of an operator’s drilling base oil produced from their MG3 plant which was evaluated through extensive laboratory studies and field trials prior to commercialization.
The base oil is based on a majority iso-paraffin component which gives an optimum kinematic viscosity, flash point and pour point for drilling applications. In addition, the drilling fluid has minimal aromatic content to fulfil international eco-toxicity standards set by CEFAS and US EPA, 821-R-11-004 Method 1619. The base oil is compatible with various oil/synthetic mud systems and additives with its low viscosity characteristic lesser than 2.4 cSt at 40 deg C which offers excellent drilling performance for Shallow and Deepwater wells. Furthermore, the base oil exhibits high flash point of more than 90 deg C to reduce potential fire hazard while drilling HPHT and ERD wells. At the same time, its superior pour point (as low as -42 deg C) suitable for storing base oil in sub-zero conditions and to be used as deep-water drilling fluid in extremely cold countries like Russia. Its unique high-performance properties provide exceptional temperature stability and optimum rheological properties throughout the extreme temperature profile of a Deepwater or HPHT well, thus resulting in a very low ECD despite drilling with high ROP.
Field trials were carried out to verify the base oil’s performance under laboratory conditions. The base oil was tested as base fluid in SBM for both Shallow and Deepwater wells. The Shallow well was drilled vertically in water depth of 105M with a maximum mud weight of 14.6 PPG and bottom hole static temperature of 280 deg F. The Deepwater well was drilled vertically in water depth of 1008 M and subsequently side-tracked to a maximum inclination of 46 degree. Both wells were drilled successfully without any drilling fluid related issues as compared to severe losses experienced with respective offset wells.
A total of approximately 138 oil and gas wells were drilled by the operator utilizing their own base oil till 2018 after completing the technical evaluation in 2014. From the field trials and actual drilled wells, a comprehensive database analysis was developed for future improvisation and broader performance portfolio. The main technical challenge for the operator was to engineer a drilling fluid system with base fluid and chemical additives to obtain minimal ECD for reducing lost circulation risk. The base fluid properties are ideal for Shallow, HPHT, ERD and Deepwater applications whereby the ECD margin for Deepwater and ERD drilling is often narrow as compared to shallow wells. The successful project execution of base oil for drilling represents a significant milestone, elevating the company’s base oil progress at par with other global base oil producers.
Panoro Energy announced an oil discovery in the Ruche North East Marin-1 well offshore Gabon. The 1 well was drilled to identify additional oil resources in the presalt Gamba and Dentale Formations in the greater Ruche Area, and completed within budget. These resources may be developed together in the future with the existing Ruche field discoveries made by Panoro in 2011 and located 3 km to the southwest. Drilled with the Borr Norve jackup unit in 115-m water depth, the well reached a vertical depth of 3400 m within the Dentale Formation. Log evaluation, pressure data, and fluid samples indicate that approximately 15 m of good-quality oil pay was encountered in the Gamba Formation and 25 m of oil pay in stacked reservoirs within the Dentale Formation.
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. The well will also appraise the Rossukon-1 reservoir, which produced 850 BOPD during tests.
Borehole gravity was pioneered by Smith and then applied to problems of reservoir evaluation by McCulloh et al. The borehole gravity meter or gravimeter responds to variations in density. Modern instruments sense a rock volume that is approximately the same as that investigated by deep resistivity tools. Unlike the shallower-sensing density log, the borehole gravimeter is insensitive to wellbore conditions such as rugosity and the presence of casing. Because the Earth is a rotating oblate spheroid, the quantity g at mean sea level varies with latitude, and it must be corrected for tidal effects. The unit of g is the Gal [1 cm/s2].
The Greater Tortue Ahmeyim (GTA) field offshore Mauritania and Senegal is a large, deep-water gas complex with two main reservoir sequences, the Lower Cenomanian and the Albian. The area was discovered by Kosmos Energy (Kosmos) in April 2015 by the Tortue-1 discovery well. Kosmos has since successfully confirmed three major fairways of the Senegal River Trend within the broader Mauritania and Senegal basin with the Guembeul-1A, Marsouin-1, Ahmeyim-2, Teranga-1, and Yakaar-1 wells. The outboard Cretaceous petroleum system offshore Mauritania and Senegal is potentially one of the largest petroleum systems ever opened along the Atlantic Margin.
Kosmos entered into a joint venture partnership with BP in respect of its interests in Mauritania and Senegal in December 2016. Dynamic production data was desired to further appraise the Lower Cenomanian reservoirs. A fast-track Drill Stem Test (DST) was conceived, planned, and conducted on the Tortue-1 discovery well beginning in June 2017 to assist in validating reservoir connectivity, productivity, original gas-in-place, and fluid quality. The DST, operated by Kosmos on behalf of the partnership, targeted two distinct reservoirs within the Lower Cenomanian sequence. The key information extracted from the well test has been used to support the Front End Engineering Design (FEED) currently underway, with a corresponding Final Investment Decision (FID) planned in late 2018.
This paper presents the objectives and design methodology, as well as the technical and operational challenges while conducting a dual-zone, high rate gas well test in ultra deep water within a compressed time schedule. This paper also presents the technology that Kosmos and BP selected to isolate the test intervals and gather pressure and temperature data during the extended flowing and buildup periods.
Finally, the key results of the DST are highlighted that underpin the development concept for the Tortue field.
The use of conventional downhole batteries, which are intended for low voltage/current, faces hurdles when it comes to operating tools designed for surface power provided through a cable. The high power consumed by some of these tools requires careful characterization of parameters such as current, transients, and battery capacity at different loads and temperatures. The battery power tool developed for high-power tools uses three battery packs, here used in series, to boost input voltage, with a provision to use three additional packs in parallel for additional current. Battery characterization efforts at currents higher than 1 A were performed at different temperatures (75 C, 100 C, and 150 C) to explore the behavior of lithium battery chemistry, with a total of 48 battery packs tested. The electronics design to boost battery voltage up to 200 V to support a pulsed neutron tool is also presented. The result of this engineering effort is a system that can provide more than 20 Ah of power and enables more than 10 hours of continuous operation of pulsed neutron tools. It also allows more than 100 hours of operation of conventional production logging tools. A tool planner software is provided for the field users to estimate the battery operation time for a specific job. Those benefits are illustrated by the field deployment results of this solution since 2014, with examples of successful operations in the Kingdom of Saudi Arabia, the Congo, and Gabon.
The promise of least-squares migration is to reduce the problems associated with standard migration being the adjoint of the forward modeling operator (Nemeth et al., 1999). In fact, the application to undersampled and irregularly acquired seismic data causes migration noise and (swing) artifacts, as well as uneven illumination in the image (Huang et al., 2014). An appropriate pre-processing sequence can help mitigate these problems, but the underlying issue remains. The large dimensionality of the seismic imaging problem means the migration inverse is only realistically solved using an iterative, gradient-based, approach. However, this is a slow and costly process involving multiple iterations of migration and de-migration. Here we present results from a practical and efficient common-offset, single iteration, least-squares Kirchhoff migration, inspired by the general idea of using non-stationary matching filters to estimate the effect of the Hessian operator (Guitton, 2004). In this paper we briefly recap the least-squares migration equations and demonstrate the uplift on resulting AVO work from an offshore Gabon data set. Then we show how to include attenuation in the least-squares migration scheme to give the overall effect of an attenuation-compensating prestack depth migration and highlight the improvement in both resolution and illumination on a Central North Sea data set.
The hydraulic fracturing industry is a fast-growing industry but the conventional hydraulic fracturing technique uses a large amount of water and a lot of harmful chemicals in order to extract more hydrocarbons from the formation which give rise to a large number of problems. Canadabased GasFrac Energy developed an innovative alternative to hydraulic fracturing which utilizes propane based gel or gelled LPG as a fracturing fluid to fracture the formation. Propane is a very clean fluid, ecofriendly and can be recovered almost 100% after the fracturing process is completed. As compared to conventional hydraulic fracturing technique, LPG fracturing provides a better fracturing length. A precursor to the poor fracturing performance is poor recovery of the fracturing fluid, often less than 50% of the fracturing fluid is recovered. This unrecovered fluid occupies the pore spaces of the reservoir matrix and becomes immobile resulting in blocking the passage for hydrocarbons. Therefore, the recovery of hydrocarbons by conventional hydraulic fracturing job is much less than that of propane fracturing, where the recovery of fracturing fluid is almost 100%. This paper will discuss about various aspects of Propane Fracturing, safety aspects during field application of this technology and its prospects in a country like India which is trying to revive its oil and gas production and has a huge potential hydrocarbon reserves including much of it's reserves still unexplored.