It is very flat, rising to only 60 feet above sea level at a distance of 150 kilometres south of the Mediterranean coast, and is both intensely populated and cultivated. This plain is bound by 30 to 60 feet escarpments of raised Pleistocene deposits which are more continuous to the west than to the east where they are interrupted by the Wadi Tumilat valley near Ismailia. Along the coast, a series of large, shallow lagoons form an almost continuous belt from Alexandria to Port Said, the largest of which are El-Burullus and El-Manzala lakes. These lagoons are sites of intensive fishing activities including aquaculture. Discontinuous coastal dunes, 15 to 60 feet high and dune fields in the east, 15 to 30 feet high, constitute the only local relief. Offshore, the continental shelf of the Nile Delta is narrow and steep at Alexandria, but increases to 50 kilometres width east of the Rosetta mouth of the Nile, as far as North Sinai. The shelf break is at water depths between 260 to 600 feet.
Domestic utilization of natural gas in Nigeria is being hampered by the poor developments in the natural gas sector over the years, with low level of electricity (generation) consumption per capital, weak legal, commercial and regulatory framework amidst poor infrastructural developments in natural gas as compared to that which exists for oil. Nigeria ranks the second in gas flaring and shows low volumes of domestic gas utilization, consuming only about 11% out of the 8.25 billion cubic feet produced per day in 2014 despite its natural gas resource endowment.
This paper examines the determinants of domestic utilization of natural gas in Nigeria from 1990-2013. It investigates its relationship as a function of price of natural gas, price of alternative fuels, foreign direct investment, volumes of gas flared, electricity generated from natural gas sources and per capital real GDP. Going further, it forecasts its likely growth rate for a short-term period, using an econometric methodology of ordinary least squares and an ARIMA model, it estimates the relationship between the variables and uses the historical trend to forecast into the future.
The result of the study showed that the determinants jointly explain the pattern of domestic gas utilization in Nigeria by 98%. Individually, per capital real GDP, electricity generated from natural gas sources and changes in the volume of domestic utilization of natural gas was found to have a positive and significant effect on domestic gas utilization. Further, the forecast values show evidence of a slow but gradual increase in utilization pattern in the near future from 2015-2020. A best-case scenario of an increase of 0.15% and a worst-case scenario of a decrease of 0.14% was presented.
In conclusion, having identified significant influences on domestic gas utilization patterns in Nigeria it is imperative that the government uses economic instrument to enhance the utilization patterns in Nigeria by improving economic activities and developing the power sector which shows significant influence in domestic natural gas utilization patterns.
The work reports an in-depth review of bulk and molecular geochemical data to determine the organic richness, kerogen type and thermal maturity of the Lokhone and the stratigraphically deeper Loperot shales of the Lokichar basin encountered in the Loperot-1 well. Oil-source rock correlation was also done to determine the source rocks’ likelihood as the source of oil samples obtained from the well. A combination of literature and geochemical data analyses show that both shales have good to excellent potential in terms of organic and hydrogen richness to act as conventional petroleum source rocks. The Lokhone shales have TOC values of 1.2% to 17.0% (average 5.16%) and are predominantly type I/II organic matter with HI values in the range of 116.3 – 897.2 mg/g TOC. The Lokhone source rocks were deposited in a lacustrine depositional environment in episodically oxic-dysoxic bottom waters with periodic anoxic conditions and have Tmax values in addition to biomarker signatures typical of organic matter in the mid-mature to mature stage with respect to hydrocarbon generation and immature for gas generation with Ro values of 0.51 – 0.64%. The Loperot shales were shown to be possibly highly mature type II/III source rocks with TOC values of 0.98% - 3.18% (average 2.4%), HI of 87 - 115 mg/g TOC and Ro of 1.16 – 1.33%. The Lokhone shale correlate well with the Loperot-1 well oils and hence is proposed as the principal source rock for the oils in the Lokichar basin. Although both source rocks have good organic richness to act as shale gas plays, they are insufficiently mature to act as shale gas targets but this does not preclude their potential deeper in the basin where sufficient gas window maturities might have been attained. The Lokhone shales provide a prospective shale oil play if the reservoir suitability to hydraulic fracturing can be defined. A basin wide study of the source rocks thickness, potential, maturation and expulsion histories in the Lokichar basin is recommended to better understand the present-day distribution of petroleum in the basin.
In a cost-sensitive market driven by depressed commodity prices, significant capital challenges exist for operators interested in pursuing exploration activities in remote environments to define their producible reserves. This paper explores the organizational and operational model developed by a service company over several remote area mobilizations; this model resulted in an optimized low-cost service delivery model characterized by top quartile operational key performance indicators (KPIs). The model centralizes critical functions of an operational organization into discrete service units that are located near the operational location or that provide remote assistance with communication and reporting lines in place to function effectively. Top quartile operational performance and tool availability is a result of placing a remote repair and maintenance facility that includes containerized specialty modules near the operational area. The upfront bottomhole assembly engineering, 24/7 monitoring, and proactive feedback of logged data, drillstring dynamics, and wellbore hydraulics are performed by a core team of subject matter experts in their respective disciplines from an established centralized operating center. The operational KPIs over the course of the six well exploration campaign provided substantial evidence to support the reliability of the model and the high level of experience used in both the remote maintenance facility and the operations center support team.
During the previous decade, an international service company was awarded a considerable volume of operational contracts to perform directional drilling and logging-while-drilling (LWD) services in remote frontier countries, including Kenya, Equatorial Guinea, Togo, and Niger.
The challenges of mobilizing a repair and maintenance facility, inventory, and equipment to a remote area with complex import and export regulations proved to be extremely time consuming and costly. The operator’s expenses for successfully drilling and logging the well, which required a continuous supply of equipment, increased as a consequence of the locally established repair and maintenance facility.
In addition to the equipment complexities, the lack of qualified inspection and machining services provided additional challenges that needed to be addressed by either providing additional equipment, again at a cost to the operator, or by running the equipment in a lower-energy drilling environment to improve equipment sustainability.
This paper presents the development, qualification and field trial of a novel well flow valve that delivers unlimited zonal selectivity in single skin lower completion without the use of control lines. Control lines have limitations and risks due to complexity during deployment, restrictions on the number of zones, complications with liner hanger feed thru and associated wet connects. It is desirable to remove the control lines whilst maintaining the functionality of multi zone, variable choke flow control.
The well flow valve is a full-bore, reliable and robust mechanically operated sleeve, qualified in accordance with ISO14998 including multiple open/close cycles, at a sustained unloading pressure of 1,500 psi, with highly customizable flow ports.
The need for such a solution was identified by an operator in West Africa. The well objective was elevated from a gas producer to a well that required the flexibility to produce gas or oil with gas lift capability. The well flow valve was selected and required on site variable choke capability for both oil and gas production, with choke position verification, ability to handle dirty gas production without risk of plugging, compliant with a high rate and high pressure proppant frac along with ease of operation and long term reliability.
The field trial included a high pressure proppant frac in the oil zone. In the shallower gas zone, three well flow valves were used to deliver variable choking capability from maximum gas flow rate with minimal delta P adjusting down to a choke size suitable for gas lift. The well flow valves were operated using a high expansion shifting key conveyed on eline through the 3 ½” production tubing. The shifting key expanded in the 4 ½” lower completion to open/close individually all the well flow valves in a single trip.
Incorporating this new product overcame the challenges presented and met the objective of commingled production of oil and gas. The well flow control valve demonstrated flexibility through design, supply chain, manufacturing, and operations. This paper will also outline the future road map covering further developments of the well flow valve and its incorporation into an enhanced flexible lower liner solution aimed at lowering well completion costs and risks.
The objective of this research paper was to explore the health, safety, sustainability and social responsibility during disposal of cutting and drilling fluids in Kenya in regard to what affects the choice of method of disposal, the Kenyan government’s regulatory requirements on disposal of the drilling wastes, methods of addressing drilling wastes, ways of reducing the volume of wastes, hierarchy of drilling wastes and the pros and cons of various methods of addressing drilling wastes. A comprehensive case study of the approach taken in Kenya with regard to handling of drilling wastes was done. Description for each approach used is provided as obtained through interviews, internet and questionnaires and statistics. Complete tables and graphs are provided and the methods are described in detail to permit readers to understand all results. The choice of method of disposal is determined and affected largely by the government policy and also by economic, technical and operation conditions and barriers. Methods of disposal included injection, thermal treatment, bioremediation, land application. This paper gives the best ways of disposal. A comprehensive description of the Kenyan government regulations is given as indicated in the Kenya Gazette, NEMA and UNEP. This paper gives insight to the acceptable drilling wastes disposal practices in Kenya and are also generally largely applicable other nations. In conclusion, it was found that Kenya would benefit from passing its own laws to regulate disposal in the coming days.
Drill cuttings and fluids disposal is one of the problems facing the oil and gas industry. Oil and gas wells drilling processes generate large volumes of drill cuttings and spent mud. Onshore and offshore operators have used a variety of methods to manage these wastes. This paper discusses various ways of addressing these wastes, the legislation governing drill cuttings and fluids disposal methods and the wastes management process.
Dubey, Pranav (Indian School of Mines) | Okpere, Adrian (Shell Petroleum Development Company of Nigeria) | Sanni, Gideon (Shell Petroleum Development Company of Nigeria) | Onyeukwu, Ifeanyi (Flowgrid)
An optimized completion design that addresses gaps in the existing single well Producer-Injector (P-I) concept is presented in this paper. Field development scenarios based on the optimized P-I concept and conventional waterflood were implemented in full-field 3D simulation models.
Detailed review of the existing single P-I well concept revealed gaps in the completion design with regards to feasibility of data acquisition, ease of well intervention and well safety/control. The existing design utilizes a Single-String-Single (SSS) design with through-tubing water injection and oil production through annulus, whilst the optimized design is a Two-String-Dual (TSD) incorporating the flexibility of independent injection/production, zonal isolation for interventions & data acquisition and additional safety completion jewelries.
A fit-for-purpose reservoir candidate was selected by assessing it’s suitability to waterflooding. The reservoir belongs to the paralic sequence of the Agbada Formation of the Niger Delta basin - a sequence of interbedded sandstones and shales. The reservoir is an elongated anticline bounded by W-E oriented faults and exhibiting channelized shoreface sediments. Porosity and permeability ranges are 17-31% and 200mD-2200mD respectively. Shale baffles strongly reduces the influence of the aquifer hence the simulation model is an oil reservoir with weak aquifer completed by the P-I well producing oil and injecting into the aquifer in tandem. Performance of the single P-I well strategy was benchmarked against conventional waterflood patterns to effectively capture the recovery efficiency and production forecast for each scenario.
Results from the five-parameter experimental design based on the P-I strategy, indicate Ultimate Oil Recovery is most impacted by horizontal permeability; injection rate, flow barrier transmissibility and vertical permeability with the least influence. Dynamic 3D water saturation maps show the waterflood front propagating principally in the horizontal direction from the injector, providing important reservoir boundary pressure support and minimizing the chance for injected water short-circuiting at the sandface.
Ultimate Oil Recovery of 5spot/line drive patterns and the P-I strategy were similar, 54% and 52% respectively. Well completion costs and forecasts were fed into simple economics spreadsheet to test which technique provides the most value. Open book economics results showed the P-I concept provides better value (NPV 23.0 and VIR 0.67) than 5 spot and line drive patterns (NPV -17 and VIR -0.14).
Ronchi, Paola (Eni Upstream and Technical Services) | Gattolin, Giovanni (Eni Upstream and Technical Services) | Frixa, Alfredo (Eni Upstream and Technical Services) | Margliulo, Chiara (Eni Upstream and Technical Services)
During the Early Cretaceous South-Atlantic opening, in large lacustrine basins a series of shallow water carbonate platforms grew along lake margins and paleo-highs. These carbonates are giant reservoirs in the
Brasil offshore, while in Angola are productive in Cabinda (Lower Congo Basin) and are being explored in the Kwanza Basin with minor success. These carbonates have peculiar facies associations represented mainly by microbialites and coquinas, and are affected by dolomitization which modified the original pore system in different ways. In presence of deep-seated extensional faults, bounding the paleo-highs, the hydrothermal dolomitization affected the reservoir carbonate improving its quality; in fact the hydrothermal dolomite produced the so-called zebra dolomite which is characterized by high porosity and permeability. On the other hand, when there is a limited influx of hydrothermal fluid, some dolomitization is observed, but it did not produce the zebra facies and the poro-perm system has lower quality. These two examples suggest that the understanding of the distribution of deep faults may help in the prediction of the diagenetic effects and resulting reservoir properties.
During the Early Cretaceous rifting the central segment of South Atlantic was characterized by a complex paleomorphology dominated by large lacustrine basins that were filled up by clastic and carbonate sediments and finally covered by restricted marine evaporites (Brink, 1974; Chaboureau et al., 2013). These thick sequences constitute important hydrocarbon plays successfully explored in both eastern and western margins of South Atlantic.
In Africa the exploration of the here deposited pre-evaporites carbonate sequences dates back to 1968 with Malongo discovery in the shallow water of Congo Basin; in the Kwanza Basin the exploration was less successful with minor recent discoveries in the deep water (Cameia, 2012). On the contrary the relatively recent exploration of the coeval carbonate sequences in Brasil offshore led to the discovery of the Tupi giant reservoir in the Santos Basin (2006) and a fast sequence of successes. An important issue of the lacustrine carbonates is the characterization of the reservoir quality linked to sedimentary facies and diagenetic overprint. The present study illustrates how the structural setting influences the diagenesis and consequently affects the reservoir quality.
Witte, Jan (Falcon Geoconsulting) | Trümpy, Daniel (DT EP Consulting) | Meßner , Jürgen (Federal Institute for Geosciences and Natural Resources ) | Babies, Hans Georg (Retired from Federal Institute for Geosciences and Natural Resources )
Several wells have encountered good oil shows in the rift basins of northern Somalia, however, without finding commercial hydrocarbons to date. It is widely accepted that these basins have a similar tectonic evolution and a comparable sedimentary fill as the highly productive rift basins in Yemen from which they have been separated by the opening of the Gulf of Aden (fully established in Mid Oligocene). We present new regional tectonic maps, new basement outcrop maps, a new structural transect and new play maps, specifically for the Odewayne, Nogal, Daroor and Socotra Basins.
Digital terrain data, satellite images, surface geology maps (varying scales), oil seep/slick maps, potential data (gravity), well data from ~50 wells and data from scientific publications were compiled into a regional GIS-database, so that different data categories could be spatially analyzed.
To set the tectonic framework, the outlines of the basins under investigation were re-mapped, paying particular attention to crystalline basement outcrops. A set of play maps was established. We recognize at least three source rocks, five reservoirs and at least three regional seals to be present in the area (not all continuously present). Numerous oil seeps are documented, particularly in the Nogal and Odewayne Basins, indicative of ongoing migration or re-migration. Data from exploration wells seem to further support the presence of active petroleum systems, especially in the central Nogal, western Nogal and central Daroor Basins.
Our GIS-based data integration confirms that significant hydrocarbon potential remains in the established rift basins, such as the Nogal and Daroor Basins. Additionally, there are a number of less known satellite basins (on and offshore) which can be mapped out and that remain completely undrilled. All of these basins have to be considered frontier basins, due to their poorly understood geology, remoteness, marketing issues and missing oil infrastructure, making the economic risks significant. However, we believe that through acquisition of new seismic data, geochemical analysis, basin modelling and, ultimately, exploration drilling these risks can be mitigated to a point where the economic risks become acceptable.
We encourage explorers to conduct regional basin analysis, data integration, a GIS-based approach and modern structural geology concepts to tackle key issues, such as trap architecture, structural timing, migration pathways and breaching risks.
Oseme, Ugochukwu (Shell Petroleum Development Company) | Awe, Sunday (Shell Petroleum Development Company) | Amah, Obinna (Shell Petroleum Development Company) | Erinle, Adeyemi (Shell Petroleum Development Company) | Akinfolarin, Ayodele (Shell Petroleum Development Company) | Ibrahim, Timothy (Shell Petroleum Development Company) | Roes, Vincent (Shell Petroleum Development Company)
Application of Managed pressure drilling (MPD) technology with other techniques to maintain constant Bottom Hole pressure (BHP) has been found to enhance drilling operations in applications where the margin between the pore pressure and fracture gradient is narrow and the reservoir permeability is high. Classic examples of such applications are deep water drilling, high pressure and high temperature (HPHT) regime and depleted reservoir environments.
In the Niger Delta, HPHT reservoirs can be found in well depths up to 17000 ftss with a drilling window range of 0.4 to1.6ppg. Typical reservoir characteristics are formation permeability of 124 - 204mD and reservoir mobility of 112 – 1000mD/cp. Generally in this type of environment and essentially where there are high uncertainties in the reservoir pressures and formation characteristics, significant process safety incidents have been found to occur during pumps off events as a result of variations in BHP outside the allowable limits of pore pressure (lower limit) and fracture gradient (upper limit). The risks of exceeding the allowable limits are the possibility of taking significant influx volume if BHP falls below the pore pressure and loss of well bore integrity if the BHP exceeds the fracture pressure. Consequences of any of these events are high nonproductive time (NPT), well cost escalation and inability to achieve well objectives.
This paper illustrates how in the recent HPHT exploration campaign carried out in Niger Delta, managing BHP was identified as a critical success factor. Hydrocarbon reserves of the exploratory objectives were successfully and safely unlocked by using MPD to maintain BHP within the allowable limits. The paper also illustrates how MPD application was enhanced by the use of high resolution pressure while drilling (PWD) technology.