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Collaborating Authors
Niger Delta
A Successful Foam Assisted Gas Lift Trial in a Matured Niger Delta Field
Okoro, Felix (Shell Petroleum Development Company of Nigeria Limited, Port Harcourt, Rivers Sate, Nigeria) | Arochukwu, Elias (Shell Petroleum Development Company of Nigeria Limited, Port Harcourt, Rivers Sate, Nigeria) | Abuah, Nnamdi (Shell Petroleum Development Company of Nigeria Limited, Port Harcourt, Rivers Sate, Nigeria) | Marcus, Imowo (Shell Petroleum Development Company of Nigeria Limited, Port Harcourt, Rivers Sate, Nigeria) | Nnanna, Erasmus (Shell Petroleum Development Company of Nigeria Limited, Port Harcourt, Rivers Sate, Nigeria) | Onuigbo-Nweze, Chy (Shell Petroleum Development Company of Nigeria Limited, Port Harcourt, Rivers Sate, Nigeria) | Eke, Iheanyi (Shell Petroleum Development Company of Nigeria Limited, Port Harcourt, Rivers Sate, Nigeria)
Abstract In the oil and gas business, continuous production optimization and enhancement is key for optimal field management. As a field depletes, water cut increases and oil rates decline. To maintain production, there is need to deploy artificial lift systems. The onshore FENE field is a matured Niger Delta field that has been in production for over 50 years. The field has wells that produces on natural flow and on gas lift. To improve field production, often requires optimization of the limited lift gas available to the gas lifted wells. Foam Assisted gas lift (FAGL) technology involves the downhole injection of a liquid foamer to lighten the fluid column and reduce slippage, thus improving well vertical lift performance. The foamer can be delivered downhole via a pre-installed downhole chemical injection line where available or into a lift gas stream on surface. The application is expected to increase oil production and / or decrease gas lift requirement. In Nigeria, a field trial was successfully carried out on two wells (Well-X and Well-Y) with water cuts greater than 60% in the onshore FENE field. The foaming agent was injected along with the lift gas via the A annulus of the wells. The field trial resulted in 280 bopd incremental net oil gain and a cumulative gain of 2510 bbls of oil for well-X and 120 bopd net oil gain and a cumulative gain of 832 bbls of oil for well-Y over the trial period of 9 and 7 days for well-X and well-Y respectively. There was also a significant reduction of water cut from an average of 76% to 66% and an estimated 25 - 35% savings in lift gas consumption. This paper details the candidate wells selection criteria, modelling details, foamers qualification, trial execution and post treatment results.
- North America > Canada > Saskatchewan (0.61)
- Asia > Middle East > Israel > Mediterranean Sea (0.61)
- Africa > Nigeria > Niger Delta (0.61)
- Africa > Nigeria > Gulf of Guinea > Niger Delta (0.61)
An Integrated Approach for the Geologic Model Construction of a Miocene Turbidite Reservoir in the Akpo Field, Niger Delta.
Author, G. O. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, C. C. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, E. A. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, O. O. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, M. O. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, V. S. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, C. O. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, G. U. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, M. F. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.) | Author, C. E. (TotalEnergies EP Nigeria Limited, Victoria Island, Lagos State, Nigeria.)
Abstract Geologic model updates especially when driven by seismic data generally help for better field understanding, and in most cases, aid the targeting of nearby undeveloped prospects or infill opportunities and robust geosteering of infill wells for efficient drainage or sweep and well recovery optimization which help to prolong field life and maximize the returns on investment of mature fields. The Akpo V & W reservoirs case study lie in the central part of the mature Akpo field. They are characterized by laterally offset stacked turbidite channels with dense network of faults. This work illustrates the collaborative team effort performed through the integration of geoscience and reservoir engineering data in constructing the static model of the V & W reservoirs. This new model aims to address the uncertainties and limitations of the previous model, re-evaluate the volumes in place, better represent the dynamic behavior of the reservoirs to aid history match, forecast and optimize infill well placements within undrained areas to sustain production. This will in turn, improve the recovery factor and the management of the reservoirs. The new model incorporates new petrophysical synthesis for all development wells, re-interpreted faults, horizons and AEs on a new seismic dataset (2018 4D M3 B98), Lithofacies trends from seismic reservoir characterization study, amongst others. Structural and property modelling results with QCs shows better respect of well, seismic data/trends and facies heterogeneities; giving rise to a more robust model that meets the specified objectives.
- Africa > Nigeria > Niger Delta (0.84)
- Africa > Nigeria > Gulf of Guinea > Niger Delta (0.63)
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.85)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.61)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OPL 246 > Akpo Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OML 130 > Akpo Field (0.99)
- Africa > Cameroon > Akata Formation (0.98)
- (2 more...)
Heavy Oil Development and Reserve Addition Potentials: The Abura-6ST Case
Ijomanta, Henry (NNPC E&P Limited, Benin City, Nigeria) | Ifeduba, Ebuka (NNPC E&P Limited, Benin City, Nigeria) | Ayeni, Olayinka (NNPC E&P Limited, Benin City, Nigeria) | Akenobo, Charles (NNPC E&P Limited, Benin City, Nigeria) | Okoh, Oluchukwu (NNPC E&P Limited, Benin City, Nigeria) | Igbokwe, Obianuju (SLB, Lagos, Nigeria) | Adebayo, Odude (NNPC E&P Limited, Benin City, Nigeria)
Abstract This paper evaluates the effect of the increment in recovery factor of the Abura Heavy Oil reservoirs on the heavy oil portfolio of NNPC E&P Limited and, ultimately, the reserve valuation of Nigeria as a country, considering that the Niger Delta basin has a significant amount of heavy oil reservoirs. The Abura field has three (3) heavy oil reservoirs (1AB6, 2AB6 and 3AB6) with viscosity ranging between 10-17cp. These reservoirs were booked as contingent resources owing to sub-optimal production using conventional techniques and sub-commerciality. An FDP study in 2018 revealed that the heavy oil reservoirs could not sustain production and hence, are uneconomically viable to develop. The initial reservoir simulation results showed flow assurance issues mainly due to the high oil viscosity and consequently poor production rate, high water cut, and high-pressure drawdown due to unfavorable mobility ratios and flow assurance challenges caused by the high oil viscosity. Improved Oil Recovery (IOR) techniques were designed to combat the highlighted issues. The combination of IOR techniques employed includes deploying a Single Well Multiple completion which allowed the completion and commingling of 2 reservoirs (1AB6 and 2AB6) in the same tubing for increased oil production, deploying an Electrical Submersible Pump (ESP) to solve vertical lift challenges, installing Autonomous Inflow Control Devices (AICDs) to allow the preferential flow of oil, hydrocarbon fingerprinting for reservoir management and production allocation, and Micro Emulsion Based (MEB) stimulation post-completion, to reduce skin due to formation damage. The results led to a significant increase in the forecasted production and, therefore, an increase in the reservoirsโ Expected Ultimate Recovery (EUR). This led to an eventual improvement of recovery factors for both reservoirs, positive migration of the contingent resources to reserves, increased revenue for the company, and a positive outlook for the numerous heavy oil resources in the company portfolio.
- Africa > Nigeria > Niger Delta (0.56)
- Africa > Nigeria > Gulf of Guinea > Niger Delta (0.25)
- Africa > Nigeria > Niger Delta > Niger Delta Basin (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OML 65 > Abura Field (0.99)
Abstract The Otakikpo field development activities commenced in 2015 with the re-entry and completion operations on Otakipo-02 & 03 wells and the installation of a 10kbpd processing facility. Due to its proximity to the shoreline, an amphibious production and evacuation methodology was implemented. This consists of batch production into onshore tanks, a subsequent evacuation into offshore shuttle tanker via an installed 6" Km offshore pipeline and final transportation to a 3 party FSO facility. The first phase of the field development was completed in 2017 and production declined from ~ 6500 bopd to ~ 4000 bopd by 2022. Green Energy successfully executed phase 2 of the field development by drilling and completing two new development wells, Otakikpo-04 and -05 wells in 2022 and field production increased to circa 10000 bopd. The production facilities limit the field production to 12,000 bopd while the evacuation infrastructure could only effectively handle about 14,000 bopd. Moreover, the field's evacuation cost is very exorbitant mostly from the cost of hiring marine vessels (2 gunboats, 2 shuttle and 2 tugboats) and paying for CHA charges at 3 party terminal. At lower production rates, the cost per barrel will be unsustainable. It is for this reason that the Operator conceptualized a phase 3 development strategy to develop and install an efficient evacuation/export strategy and thus reducing overall OPEX $/bbl. It also plans to make the Otakikpo field a crude processing and export hub in the Eastern Niger Delta area. To achieve this, the operator plans to construct an onshore terminal and export infrastructure very close to the field. This consists of a scalable onshore terminal with an initial 750,000 barrels of oil storage capacity located within the field with a 360,000-bpd pumping and metering capacity for loading tankers. It also includes a 20" ร 23km offshore export pipeline connecting the terminal to an unmanned single point mooring (SPM) crude offloading system. The terminal is expandable to store circa 2 million barrels of crude with a daily processing capability of 250,000bopd. The proposed Otakikpo onshore terminal is conceptualized as a national infrastructure with potential to unlock significant stranded national reserves. It will be the first new onshore terminal in Nigeria in over 50 years, and first to be non-IOC owned and operated. Moreover, the terminal is expected to create significant value for the over 20 stranded marginal fields that are in proximity to terminal which would benefit from access to readily- accessible, cost effective and fit for purpose evacuation infrastructure. This paper aims to highlight the justifications for the Otakikpo onshore terminal, lessons learnt during the conceptualization and design stages, status of the project, opportunities for future expansion and its potential role in the energy security of the nation in future.
Abstract The Otakikpo marginal field was carved out of OML 11 and is situated in the southern part of the license. Green Energy International Limited, the operator, successfully implemented the first phase of the field development between 2015 and 2017. This was followed up with a 2 phase in 2022. The field currently produces circa 11000 bopd. Due to its proximity to the shoreline, an amphibious production and evacuation methodology was implemented. This consists of batch production into onshore tanks, a subsequent evacuation into offshore shuttle tanker via an installed 6", 6 Km offshore pipeline and final transportation to a 3 party FSO facility. The end of the offshore leg is connected to a PLEM (Pipeline End Manifold) which acts as interface between marine pipeline and the submarine hose system. The mooring systems consists of 2 gravity anchors (5tons each ~ port and starboard); 200m steel anchor chains; 40m sling wire; 20m sling wire; and a 100m pick up rope. However, the offshore environment experiences a significant adverse weather condition between March and December that peaks between June and November every year. Often, it could take professional divers up to 5 days to pick up rope from the seabed depending on weather condition. There were cases of incessant twisting, tension and curling as the hose is exposed to swinging by ocean swell and current leading to loss of operational integrity of the offshore system. Restoring the integrity of the system led to significant operational downtimes as high as 20 days per year; a situation that was not sustainable for a marginal field producer. The GEIL engineering and operations team developed and implemented several vintages of design modifications over time to mitigate these concerns. The team realized that the most challenging part of resolving the hose swinging issue was finding a way to keep it fixed, in such a way that the hose end does not move under any weather condition(s). To achieve this, the team designed and installed a Crossbar + Buoy system. The Crossbar was installed on the seabed, while ensuring the height is above the water surface. A boat is used to unhook and hook up the cargo hose to the Crossbar before and after every shuttle loading respectively. This allows for a more efficient pick up and transfer of hose to tanker (10 mins) by professional divers while eliminating the challenges with hose twisting which usually results in hose curling around the PLEM and incessant shutdown from the EPF. Luckily for our operations, there was no spill recorded in these scenarios due the effective communication between EPF and the marine team, and timely shutdown of crude flow from the EPF. This paper aims to highlight the seasonal integrity challenges faced by the Otakikpo offshore evacuation system, its effect on operational excellence and the various stages of the elegant solutions developed and implemented.
Abstract The Otakikpo marginal field was carved out of OML 11 and is situated in the southern part of the license. The field was discovered with Otakikpo-02 in 1983 and was further appraised with Otakikpo-03 in 1986. The wells encountered hydrocarbons in 4 stacked oil and gas bearing sands (C5000, C6000, C7000 and E1000). The field is operated by Green Energy International Limited (GEIL). The field currently produces ~10,500 bopd with significant associated gas (AG) production from the wells with average GOR of ~1000 scf/bbl. Compositional analysis shows that the associated gas is rich in C3 โ C4 components (~ 8%) and C5 โ C7 (~ 3%) making it ideal for NGLs (LPG and condensates) extractions. Most natural gas utilization projects require securing constant gas production contracts for between 10-20 years and for constant rates > 50 MMSCFD. However, the Otakikpo field, the associated gas reserves do not meet this threshold and the production profiles are at best unpredictable. To address these issues, an innovative strategy is required to accelerate reduction in the field's AG flaring. A qualitative and quantitative screening of the various gas utilization concepts against some critical decision drivers (AG production profile, scalability, CAPEX) led to the recommendation of a modular LPG extraction plant for the heavier components of the AG and Gas to Power for the lean gas. The conventional approach of piping gas from a remote field needs to be replaced with a less orthodox technique of "bringing the plant to the gas". This eliminates the need for expensive pipeline and compression since the facility is within the Otakikpo field flow station. Furthermore, a modular scalable strategy with small footprint plant that is quick to deploy and easy to relocate was recommended as the best solution for the field. The Operator successfully commissioned the 12MMSCFD modular LPG extraction plant and 6MW power generating plants. This scale of modular LPG plant will be the first to be installed in the country. This strategy could be adopted by other small fields in addressing AG flares caused by stranded pockets of gas located in oil fields in the Niger Delta thus supporting the Government's aspiration of eliminating AG flares.
Integration of Technologies for Heavy Oil Production โ An NNPC E&P Ltd Approach
Ifeduba, E. A (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Ijomanta, H. U. (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Hamza, S. M. (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Ayeni, O. M. (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Udo, N. A. (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Niyang, A. S. (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Okoh, O. M. (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Akinnurun, Y. S. (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Ogweda, M. (NNPC E&P Ltd, Benin-city, Edo, Nigeria) | Emetoh, T. (Tuwal Ltd, Victoria Island, Lagos, Nigeria) | Esene, J. O. (Rhino Production Solutions Ltd, Lekki, Lagos, Nigeria) | Ojeaga, B. (Rhino Production Solutions Ltd, Lekki, Lagos, Nigeria)
Abstract NNPC E&P Ltd (NEPL) recently successfully drilled, completed and tested the Abura 6ST well which integrated multiple Improved Oil Recovery techniques to develop some heavy oil reservoirs in the Abura field. The 1AB6 and 2AB6 reservoir fluids have viscosities of 10 and 17 Centipoise and API gravity ranging from 16 โ 20APIยฐ which is a marked variation from NEPL's conventional resources. NEPL is estimated to have over 1.2B barrels of heavy crude oil in her portfolio therefore an attempt to unlock the potential from these reservoirs had a lot of implication for the company. Conventional methods of producing this reservoir were not economically viable mainly due to the high oil viscosity and consequent preferential flow of water rather than oil. The NEPL team resorted to integration of multiple improved oil recovery IOR techniques to ensure an economically viable well.The first of such improved oil recovery techniques was the use the ESP as the Abura field did not have any gas source for gas lift. Artificial lift was to eliminate flow assurance issues that such a hydrocarbon system would have. Another IOR technique was the combination of horizontal and deviated well bores to drain the reservoirs through a single wellbore in a commingled fashion. The well cuts across the shallowest reservoir as a high angle section and lands in the deeper reservoir as a horizontal well. To ensure preferential flow of oil from the reservoir into the wellbore, Autonomous Inflow Control Device AICD was deployed for both the horizontal and vertical sections of the completion which uses viscosity differences to prevent early water breakthrough and reduce water production. To meet NUPRC's back allocation requirements, hydrocarbon fluid samples were collected during the drilling operation and unique fingerprint markers were identified which will aid in the determination of each reservoir's production contribution for proper hydrocarbon accounting. In the completions aspect of the design, Swell packers for zonal segmentation, Micro-emulsion breaker system for near well-bore remediation and improved permeability, downhole gauges & sensors and a Y-Tool assembly for alternate access in rigless intervention mode. The Abura 6ST well produced circa 2900 BOPD on choke 28/64 and ESP frequency of 40Hz.This paper seeks to elucidate on some of the IOR technologies and how they were integrated to facilitate the delivery of the first heavy oil ESP well in NEPL's direct operations.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Africa Government > Nigeria Government (0.61)
Carbon/Oxygen Logging Speed Optimization in the Niger Delta Fields With Improved Pulsed Neutron Technology
Akagbosu, P. I. (Baker Hughes, Port Harcourt, Rivers State, Nigeria) | Kim, Y. (Baker Hughes, Seongnam, Gyeonggi-do, South Korea) | Nardiello, N. (Baker Hughes, Milan, Italy) | Chace, D. (Baker Hughes, Houston, Texas, USA) | McGlynn, I. (Baker Hughes, Houston, Texas, USA) | Lawal, O. (Chevron, Lagos, Lagos State, Nigeria) | Akomeno, K. (Chevron, Lagos, Lagos State, Nigeria) | Toumelin, E. (Chevron, Lagos, Lagos State, Nigeria) | Atuanya, C. (Chevron, Lagos, Lagos State, Nigeria)
Abstract Pulsed neutron logging of salinity-independent carbon/oxygen (C/O) mode typically requires slow logging speed (e.g., 2 feet per minute (ft/min)) and multiple passes, and it has always been a concern in the upstream rig operations because of the rig time involved, which translates to higher costs for operators. Reservoir fluid volumes, properties, and contacts change over time in cased wells, such as in the Niger Delta oilfields, produced for over four decades. Time-lapse C/O logging is required in this freshwater environment to determine two-phase saturations and fluid contacts, evaluate fluid dynamics, and identify bypassed oil zones. Due to the higher cost of C/O logging campaigns than pulsed neutron capture (PNC) logging campaigns, it is imperative to consider faster C/O logging speed, hence the advent of an improved pulsed neutron technology capable of logging three times faster than previous tools. The critical properties of the improved pulsed neutron technology are the lanthanum bromide (LaBr3) material chosen for the detector section due to its high density and resolution characteristics, higher pulsed neutron source output, this capable of producing two times the neutrons produced by previous generation tools, and the new digital electronics system capable of processing the increased gamma-ray count rate. The new instrument allows three times faster logging when multiple passes are recommended or improved precision at legacy logging speeds. Indeed, one pass of the new tool at 2 ft/min is equivalent to three passes of the legacy tool at 2 ft/min. Recent papers (Nardiello et al., 2022; Kim et al., 2023) described the comparison demonstrating that the upgraded, faster technology provided the same data precision and saturation interpretation as the slower, legacy technology, achieving considerable time reduction in logging operations. This paper intends to present an example of the Niger Delta field's C/O data logged with the new tool at 6 ft/min and a formation saturation analysis case study. The saturation analysis result identified a watered-out sand due to offset well production (or a formation water-oil contact change).
- North America > Canada > Saskatchewan (0.92)
- Asia > Middle East > Israel > Mediterranean Sea (0.92)
- Africa > Nigeria > Gulf of Guinea > Niger Delta (0.92)
- Africa > Nigeria > Niger Delta (0.83)
ABSTRACT To reduce greenhouse gases in industrial fields, IMO(International Maritime Organization) has implemented regulations to actively reduce CO2 emissions from shipping through regulations such as EEDI, EEOI(Energy Efficiency Operational Indicator), CII(Carbon intensity Indicator), etc. In this paper, EEDI of 2 target vessels are calculated with the information on the type and size of those ships, along with the engine types and power. In addition, the results of applying technical measures to satisfy the IMO regulations are also discussed. The obtained results suggested the fuel change from MDO to LNG is the most effective way to reduce EEDI considering the current situations of the limited supply of alternative fuels. Decreasing ship speed was the next effective option to meet the regulation until phase 4. However, for both vessels, an additional measure is required to meet Phase 5, demanding a reduction of 70%. The Onboard CCS system for KCS and KVLCC2 was designed to meet the phase 5 from the process simulation. INTRODUCTION Various serious problems caused by global warming are occurring around the world, and eco-friendly decarbonization regulations have recently been conducted to solve this issue. In the shipping field, the IMO(International Maritime Organization), which oversees maritime affairs around the world, has implemented related regulations. As one of the efforts, newly constructed ships must meet the standards of EEDI(Energy Efficiency Design Index) regulation as of 2013, indicating the amount of carbon dioxide emission to transport a ton of cargo for one nautical mile. To satisfy this, newly built ships after 2013 need to be designed energy-efficiently from the first stage(MEPC.203(62), IMO, 2011), and research on linear and propulsion system improvement is being actively conducted because the amount to be reduced step by step increases. To improve the index, several methods have been proposed. One is converting to a propulsion system using LNG(Liquefied Natural Gas), not low sulfur fuel oil or existing bunker oil, and another is on-board CCS(Carbon Capture and Storage), collecting CO2 emitted from ships by installing associated facilities. At the same time, there are also other methods which are the reduction of a ship's waterside resistance by modifying the head side of a ship or the attachment of an ESD(Energy Saving Device) on the propeller to increase propulsion efficiency. It is known that attaching an ESD has an effect of a 5% increase on average in transmission power.
- Transportation > Marine (1.00)
- Transportation > Freight & Logistics Services > Shipping (1.00)
- Energy > Oil & Gas > Downstream (1.00)
TotalEnergies' flagship ultradeep Egina field won the Excellence in Project Integration Award at the 15th International Petroleum Technology Conference (IPTC) held earlier this month in Bangkok, Thailand. One of three finalists named in January, Egina took top honors after each finalist made a presentation at the conference before the winner was announced during the IPTC opening ceremony. General Manager, Preowei Development Packages, Paul Timitula Brisibe, who made the company's presentation at the event, noted, "Partnership and collaboration amongst all stakeholders, technological expertise, and local commitment made Egina a Nigerian project with global footprint." It's indeed a good achievement to the company and our partners, and we must find a way to communicate the great feat to our teams that were fully involved in the project (past/present)," Deputy Managing Director, Deepwater, Victor Bandele said when he received the news. The President EP, Nicolas Terraz, said the award was a testament to the commitment, hard work, and dedication of the TotalEnergies EP Nigeria and TotalEnergies Upstream Nigeria Limited teams.