Bonga Field Research Articles

First report on the occurrence of Sargassum Weed Fish Histrio histrio (Lophiliformes: Antennariidae) in Nigeria deep water, Gulf of Guinea

We report the first occurrence of Sargassum Weed Fish Histrio histrio at Bonga Field in Nigeria Outer Continental Shelf approximately 120 km south-east of Delta State in February 2014. At high tides and under difficulty, we sampled some seaweeds in the epi-pelagic realm using a secured standard plankton net to the environmental research vessel that was cruising at a dead speed (≤4 knots). Upon examination of the weeds we collected, one adult Sargassum Weed Fish along with two gelatinous fingerlings were realised. This finding suggests the probable occurrence of more population of Sargassum Weed Fish in their macro-habitat (the Sargassum seaweeds) which are abundantly bound in the Gulf of Guinea deep waters. The specimen was photographed on-board and preserved immediately in 10 % formalin solution for a 24-h period and was thereafter reprocessed, and permanently preserved with 70 % ethanol. We recommend a major study of the marine seaweeds and their colonisers amongst Gulf of Guinea member states.

DELINEATION OF HYDROCARBON SATURATED RESERVOIR SAND USING INTEGRATED 3D PRE-STACK SEISMIC AND WELL LOG DATA IN BONGA – FIELD, CENTRAL SWAMP DEPOBELT, ONSHORE NIGER DELTA, NIGERIA

This study has successfully delineated the lateral continuity of hydrocarbon saturated sand reservoir in Bonga field, Niger Delta. 3D pre-stack seismic volume and well logs from two (2) exploratory wells were employed in the pre-stack seismic inversion analysis. The delineated BGA reservoir sand spans across the two (2) wells labelled Bonga-26 and Bonga-30. The reservoir depth ranges from 10490 ft to 10620 ft in Bonga-26 while the reservoir depth ranges from 10390 ft to 10490 ft in Bonga-30. The delineated reservoir is characterized by low gamma ray (< 75 API), water saturation, shale volume and high resistivity as deciphered in their respective well log curves signature. Rock attribute crossplot was carried out to discriminate between the formation fluid and lithology. The crossplot space of VP-VS ratio versus acoustic impedance (AI), discriminates the formation properties into lithology and fluid (gas and brine sand) based on clusters inferring the presence of each formation fluid properties. The inversion cross sections of P-impedance, S-impedance, density (ρ) and VP-VS ratio depicts the spread and lateral continuity of the reservoir sand across the well locations. The delineated zones reveal low P-impedance, density, VP-VS ratio and slight increase in S-impedance which further validate the presence of hydrocarbon in the field.

First time-lapse OBN in Bonga deepwater offshore field

Time-lapse seismic data from Bonga Field, located in deepwater Nigeria, have delivered excellent results previously from dedicated streamer seismic surveys (2000, 2008, and 2012) that image changes in amplitude due to water replacing oil. One challenge with the streamer data is the presence of a floating production storage and offloading (FPSO) unit. It is difficult to accurately repeat streamer acquisition geometry in economically important updip regions of reservoirs that lie beneath the FPSO. To ensure an accurate repeat of this area, we acquired an ocean-bottom node (OBN) survey in 2010 and carried out the first time-lapse OBN repeat of the survey in 2018. Time-lapse processing of the OBN data produced excellent results. We obtained an OBN-on-OBN normalized root mean square (NRMS) difference repeatability of 6%. This was an improvement over the 12% NRMS for streamer-on-streamer repeats. The OBN data quality was unaffected by the FPSO, enabling us to properly image the changes occurring in this area. The 4D OBN interpretation was used to identify bypassed oil opportunities. The data also were used to derisk well placement, optimize water injection, and update the dynamic reservoir models. The new models are essential to enhance predictability and field performance. We also analyzed an area northwest of the field where we extended the 2018 OBN acquisition and compared it to streamer data to optimize a new injection well location.

Comparison of microbial communities involved in souring and corrosion in offshore and onshore oil production facilities in Nigeria

Samples were obtained from the Obigbo field, located onshore in the Niger delta, Nigeria, from which oil is produced by injection of low-sulfate groundwater, as well as from the offshore Bonga field from which oil is produced by injection of high-sulfate (2,200ppm) seawater, amended with 45ppm of calcium nitrate to limit reservoir souring. Despite low concentrations of sulfate (0-7ppm) and nitrate (0ppm), sulfate-reducing bacteria (SRB) and heterotrophic nitrate-reducing bacteria (NRB) were present in samples from the Obigbo field. Biologically active deposits (BADs), scraped from corrosion-failed sections of a water- and of an oil-transporting pipeline (both Obigbo), had high counts of SRB and high sulfate and ferrous iron concentrations. Analysis of microbial community composition by pyrosequencing indicated anaerobic, methanogenic hydrocarbon degradation to be a dominant process in all samples from the Obigbo field, including the BADs. Samples from the Bonga field also had significant activity of SRB, as well as of heterotrophic and of sulfide-oxidizing NRB. Microbial community analysis indicated high proportions of potentially thermophilic NRB and near-absence of microbes active in methanogenic hydrocarbon degradation. Anaerobic incubation of Bonga samples with steel coupons gave moderate general corrosion rates of 0.045-0.049mm/year, whereas near-zero general corrosion rates (0.001-0.002mm/year) were observed with Obigbo water samples. Hence, methanogens may contribute to corrosion at Obigbo, but the low general corrosion rates cannot explain the reasons for pipeline failures in the Niger delta. A focus of future work should be on understanding the role of BADs in enhancing under-deposit pitting corrosion.

Comments: Nigeria's Reforms

Editor's column Nigeria is the latest major oil and gas producer to reform its oil structure and national oil company (NOC) to take advantage of high oil prices and increasingly valuable hydrocarbon resources. Nigeria's new president, Umaru Yar'Adua, took office less than a year ago but has wasted little time trying to revitalize an oil industry that has been plagued in the past by sabotage, worker strikes, and charges of corruption. Leading the reforms are several prominent industry figures who have lent credibility to the initiative, including Emmanuel Egbogah, an SPE director who was an adviser to Malaysian state oil company Petronas for several years; Rilwanu Lukman, a past long-term secretary general of OPEC; and Tony Chukwueke, who worked for Shell, the largest international oil company (IOC) producer in the country, for almost 3 decades. In an interview beginning on page 26, Egbogah, special adviser to the Nigerian president on petroleum matters, lays out the reforms and the thinking behind them. The reforms in Africa's biggest oil exporter will put more pressure on IOCs, which by now are getting used to national oil concerns wresting more control and revenues from oil projects. But these reforms are likely to go over better than the changes that have taken place in Venezuela and Russia, for example, and could benefit IOCs in the long term. Nigerian projects have been hampered by worker unrest and lack of financing on the government's end, which has slowed progress significantly on some major projects. Nigeria has been producing about 2.2 million BOPD, although its production capacity is anywhere from 2.47 million BOPD (according to the International Energy Agency) to 3 million BOPD (according to the Nigerian government). With reserves of 35 billion bbl, Nigeria accounts for 60% of proven oil reserves in the strategically important Gulf of Guinea. The renegotiation of contracts will increase the profits of Nigeria at the expense of the IOCs. Many of the existing contracts between the state oil company, the Nigerian National Petroleum Corporation (NNPC), and private companies were signed when oil was valued in the USD 20/bbl range. Six joint ventures between the Nigerian government and Shell, ExxonMobil, Chevron, Eni, and Total account for 90% of the country's production. With the majority stake in each of the projects, Nigeria provided the larger financial contribution, but it sometimes had difficulty making the cash call. Lacking the money to meet its joint-venture requirements for deepwater exploration in the Gulf of Guinea in the 1990s, Nigeria signed agreements that allowed IOCs to invest their capital and recoup their own costs before sharing profits with the government. Several big finds have been made since then, including Shell's Bonga field and Chevron's Agbami field. It is those agreements in particular that the government wants to revisit. The reforms will also allow NNPC, which was formed in 1977, to operate more nimbly, like other NOCs, such as Petronas. Many NOCs are now negotiating tougher contract terms at home while exploring new areas abroad. The measures could also help the country develop its vast reserves of gas and a liquefied-natural-gas industry.

Use of Nitrate to Mitigate Reservoir Souring in Bonga Deepwater Development Offshore Nigeria

Summary The Bonga field, located in deep water off the Nigerian coast, needs pressure support to effectively recover hydrocarbons. The strategy is to inject 300,000 BWPD of seawater from the start of oil production. During the field development in 1999, it was concluded that Bonga was expected to suffer from reservoir souring and that mitigation would be necessary. Initial data gathering indicated that the H2S content resulting from reservoir souring was not expected to exceed 50 parts per million(volume-based) [ppm(v)] in the gas phase. Initially nanofiltration to reduce the sulfate level in the seawater was identified to mitigate reservoir souring, but because of the high capital-expenditure (CAPEX) costs, it was dropped and, because there were no other proven mitigation techniques available, it was decided to operate without mitigation. The strategy for this project was to let the reservoir sour and handle the H2S with sour-service materials and scavenging facilities topside. The facilities were designed to handle a maximum level of 50-ppm(v) H2S. As detailed design progressed and more field data became available, doubts were raised on the suitability of this approach. The strategy to let the reservoir sour and handle the H2S at surface was re-evaluated in 2003. It was found that H2S levels are likely to exceed 50 ppm(v). Since then, a new strategy with mitigation was adopted. Several operators had verified that nitrate injection is an effective mitigation technique to control H2S development. However, to date, the main application for nitrate had been the reduction of H2S in already-sour fields, and the experience for the use of nitrate from the start of the water-injection scheme was limited. This paper presents a detailed evaluation of the potential for reservoir souring resulting from biogenic reservoir souring in the Bonga field and the work done to predict H2S levels. The paper focuses on the selection of nitrate as a mitigation method. Introduction The Bonga field (Fig. 1) lies on the continental slope in the southern part of the Niger Delta, some 120 km offshore, southwest of Warri, in Nigeria, with water depths ranging from 950 to 1500 m. The reservoirs are Lower/Upper Miocene in age, and are interpreted as stratigraphically/structurally trapped mud-rich unconfined-turbidite systems in a mid-/lower-slope setting. The reservoirs are composed of fine-grained amalgamated channel sands derived from the shelf margin to the northeast. The main 702 reservoir, which is expected to deliver more than half of the recoverable reserves, comprises amalgamated turbidite channels. The other reservoirs are stacked either above (690) or below (710/740, 803), and are generally less-well amalgamated. Net reservoir thickness is generally less than 100 ft. Measured sand porosities range from 20 to 37% and are generally associated with high (multi-Darcy) permeabilities. Seawater injection for pressure maintenance and sweep is key to the success of the Bonga development. A total of 16 wells (nine oil producers and seven water injectors) were drilled during the Bonga Phase 1 drilling campaign. All fluids produced were processed on a floating production, storage, and offloading (FPSO) facility situated centrally in the field, and oil was loaded directly to tankers (Fig. 2). The associated gas was exported through pipelines. Water was processed to appropriate standards and disposed of overboard. Since the beginning of the project, reservoir souring has been identified as an area of concern in Bonga. Reservoir (e.g., mineralogy, temperature, pH, and pressure) and fluid characteristics (e.g., composition) were recognized to be favorable to sulfate-reducing-bacteria (SRB) activity. With more samples collected and analyzed, the reservoir-souring potential has been recently re-evaluated and mitigation techniques have been upgraded on the basis of new technology developments. This paper presents the work conducted to determine the souring potential of the field, with most of the focus on the 702 reservoir, and will introduce the revised mitigation techniques being implemented.

Doubts cloud Nigeria's production outlook

Following a series of production setbacks, Nigeria has announced that its output capacity will rise by 0.5 mn bpd between now and the end of the year to 3.0 mn bpd. Production has been hit by unrest in the oil‐producing Delta region, sabotage to pipelines, strikes and the theft of substantial volumes of crude oil. The government has recently declared that the security situation has improved and that some 140,000 bpd of production at Chevron's Escravos field‐shut in by unrest since March 2003‐will be restored before the end of the year. A further 125,000 bpd is due to be added when Shell's deep‐water Bonga field is commissioned later this year. Nigeria may nevertheless struggle to hit this year's capacity target and future ones as well.

Integrated seismic and subsurface characterization of Bonga Field, offshore Nigeria

The key to successful development planning is the building of earth models integrating all relevant subsurface data and predicting reservoir performance in the presence of uncertainties.

ABSTRACT: Bonga Field, Deepwater Nigeria: Comparison of Near-Surface, Well-Calibrated Submarine Channels with Reservoir Channel Sands

Comparison of near-surface channels with channel reservoirs at Bonga, offshore Nigeria (OML118, 1000 m water depth), demonstrates some important lessons in using shallow analogs for reservoir prediction. Studies of shallow hazards and pipeline routing, integrating 3D and high-resolution 2D seismic with well logs, illustrate seafloor and nearsurface features including a large mud-draped canyon, mud volcanoes, and numerous pockmarks, which indicate fluid expulsion. Both the shallow overburden (Plio-Pleistocene) and the main reservoir intervals (Miocene) are characterized by deepwater channel geometries visible in seismic profiles, on map views, and within 3D volume views. Most near-surface channel features inhabit broad, relatively straight scours 1-3 km wide and 30-300 m deep, filled by composite packages of smaller, often sinuous channels 100500 m wide and 5-50 m deep. Although many of these near-surface channels display a chaotic to low-continuity, high-amplitude seismic facies character often associated with sandy fill, well logs through the near-surface section indicate these are mainly filled with mud. Channel geometries at reservoir level show different characteristics. The smaller-scale map-view geometries are consistent in size with the near-surface channels but the larger host scours are not as prevalent or obvious, and some thin, sheet-like sands are also present. A transition from lower slope to upper slope at the end of the Miocene probably accounts for this variation. A fundamental understanding of geologic setting and rock/fluid variation is critical before extrapolating seismic facies information from shallow analogues to deeper reservoirs.

ABSTRACT: Bonga Field Development, Offshore Nigeria - A Deepwater Giant

ABSTRACT: Bonga Field Development, Offshore Nigeria - A Deepwater Giant

Abstract: Bonga field - A New Deepwater Giant

Abstract: Bonga field - A New Deepwater Giant