This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
In deep water, subsea approach is often non debatable. Besides, subsea solutions are often selected because a platform-based development would not be profitable. However, due to very large combinatorial size of the design and operational decision space for the Platform versus subsea solutions, the selection between Platform and subsea solutions is a matter of doubt unless having large reserves or complex reservoir. Based on experience acquired through various subsea gas projects, the paper outlines some standard blocks for subsea production system based on mature and field proven components. In this context, flexible architectures along with Tieback options with existing infrastructure and its related de-rating will be illustrated. Subsea gas compression standard template solution along with its control system requirement will be overviewed. Key factors are highlighted in order to take sufficient account of options value. This will be very helpful for concept selection especially for stranded/ marginal fields allowing unlocking of new opportunities for profitable production where shallow water subsea systems can be an ideal solution for improving net present value.
Usan, a deepwater field located offshore of Nigeria, commenced production in February 2012 with development drilling to be completed in 2016.
The field has 2 subsea flowline loops with 4 risers giving the flexibility to flow wells through two different risers. Due to the constrained flowline capacity, optimization of well routing and drillwell sequencing became critical to sustain the remaining drillwell campaign while maximizing base production and incremental uplift. The adopted approach by the Production and Reservoir Engineering teams was to utilize the Integrated Production Modelling (IPM) software suite (PROSPER, GAP & RESOLVE) to ensure optimal well mix and flow stability.
A systematic approach of continuously testing various routing scenarios of wells within the different production loops was applied to minimize production back out loss due to system hydraulics during the streaming of new drillwells. Different ramp-up scenarios were also tested for the new wells to minimize back-out on base wells. Due to variations in fluid properties, reservoir pressures, depletion strategies and loopline distance, the system needs to be re-evaluated frequently. With over 50 routing sensitivities assessed at each evaluation, identifying and implementing the optimal routing/configuration became critical.
Production optimization using the IPM model has led to higher FPSO incremental rates from new drillwells due to optimized well routing within the production risers. This has also helped to sustain the ongoing drilling campaign in the Usan field and improved the economics of the overall project.
This paper describes how IPM software was used to maximize incremental production from new drillwells.
The Ofon field operated by Total E&P Nigeria was developed over 16 years ago and has since been producing Oil & Gas. With the identification of additional field potential, an upgrade of the facilities was conceptualized to increase hydrocarbon production and most importantly to produce the enormous gas reserve for LNG export with the stoppage of associated gas flaring, this became the Ofon2 Project. The upgrade had to be done while minimizing losses to production, which meant that the major activities (Construction and Production) on site were going to be done in parallel in what is known as Simultaneous Operations (SIMOPS).
The objective of this paper is to share the experience of the field in the management of various aspects and implementation of systems to effectively embark on the brown field development project with the attendant risk associated with simultaneous operations.
The field upgrade project brought along several constraints such as optimizing production, limitation on activities offshore as a result of space constraints, multiple contractors carrying out co-activities etc. The paper also elaborates the various challenges arising from an Offshore Brownfield field development such as astronomical increase in the number of Personnel on site, especially those employed by the different contractors, cross cultural aspects such as working with people from different parts of the world with different attitude, behaviours, performance, languages, different HSE management systems and objectives and finally, the integration of the new and existing facilities.
Several initiatives were taken to overcome the impact of the various aspects encountered during the project. These include but not limited to Personnel & contractor management, effective work organization, HSE management systems coordination, etc.
We shall conclude by highlighting the main HSE performance, the lessons learnt and keys to success for the integration, hook-up, and commissioning and start-up activities of the Project. The HSE strategies and its successful implementation demonstrate that Brownfield developments can be achieved with minimal impact on HSE performance.
Usan is a highly-compartmentalized deepwater field offshore Nigeria with both structural and stratigraphic barriers across and within the compartments. The reservoirs were at their mechanical seal capacity based upon evaluation of reservoir and leak-off pressure trends. This complicates gas injection and pressure maintenance in the Usan field.
Due to the lack of gas export channels, gas injection was adopted as part of the development plan for the field in addition to water injection. During the first 18 months of production, less than 40% of produced gas was reinjected due to reservoir pressure/leak-off constraints.
A gas injection strategy was developed based on a number of uncertainties which included actual crestal depth, fracture pressures, and communication within and across compartments. To maintain or increase gas injection, the team needed
A novel approach was used in better determination of the crests using fracture and fluid gradients. Safe injection pressures were based on dynamic injection pressures rather than static reservoir pressure. With these estimated crest depths and fracture pressures for the gas injection compartments, volume-depth curves were used to determine gas column height and safe injection pressures were calculated for each gas injector. Due to the mechanical seal integrity concerns, a monitoring system was developed to avoid the risk of fracturing the reservoir with continued injection. The surveillance strategy utilizes real-time flowing well pressures, short duration shut-in pressures, and evergreen volume-depth curves.
Ultimately, managing reservoir pressure levels and trends in each compartment allowed for increase in overall gas injection in comparison to previous methodology. A 30% increase in gas injection rate was immediately achieved. Optimal gas injection has also been maintained resulting in improved oil recovery.
This paper focuses on the methodology of determining/applying safe gas injection targets and maximizing oil recovery within the known constraints and uncertainties.
With the recent decline in price of crude, more cost effective ways are explored to ensure that the production rates are sustained and increased. The need for cost effective subsea well intervention has been discussed and documented over the last few years. The increasing number of installed subsea wells combined with the increasing age of subsea fields continues to drive demand for more efficient subsea well intervention.
Traditionally the accessibility to subsea wells is considered more difficult and represents a large cost compared to wells with direct platform access. Even minor jobs represent large expenses, leaving a gap between intervention frequency on subsea wells and wells with direct platform access. The average recovery rate for a subsea well is considerably lower than that of a comparable surface well due to the relatively more complicated well intervention and maintenance issues. Using heavy and traditional rigs for subsea intervention is costly and time consuming due to the high day-rates and mobilization aspects. The base costs are therefore considerable higher as compared to surface well intervention where tools can be deployed directly through the risers from the production unit.
At Addax Petroleum, Nigeria, the re-entry and intervention of existing poor producing subsea wells was identified as a cost effective method to maintaining production in the reasonably high cost oil subsea environment. However the major challenge with subsea intervention is the uncertainty that surrounds the planning and operations which grows exponentially with the age of the well. As factors like corrosion, and well integrity (cement and casing) all become critical in the successful delivery of the well. The availability of required service equipment and modes of operation also become very critical especially for old and obsolete Subsea equipment. There is always a significant extra cost spent if any of the identified or unidentified risks manifest.
In 2014 Addax Petroleum embarked on a successful re-entry campaign as part of the second phase of its Okwori Field Development Plan. This paper highlights on the lessons learned from the campaign, discussing the challenges, planning, and execution phases of the successful well re-entry campaign in deep water operations.
Marginal oil fields in Nigeria, some of which the International Oil Companies (IOCs) have abandoned for over 10 years previously, are now being awarded to indigenous oil companies. Due to difficulty with raising development finance domestically, some of the indigenous Marginal Field Operators (MFOs) have resorted to allowing foreign-listed Financial Partners (FP) to'carry' their share of development costs. We test the optimality of such'carried' cost arrangements by using the discounted cash flow method to analyse the economic viability of two model marginal fields (one onshore and the other offshore) in the Niger Delta/Gulf of Guinea region. Four different scenarios (sole risk [MFO], sole risk [FP], joint venture without carry, and joint venture with carry) for each model are compared. The empirical results appear to imply that marginal field operators are better off if they can contribute their share of development costs, by equally sourced debt and equity financing domestically, than when they are carried by a foreign financial partner. The computed net present value (NPV), NPV per barrel, modified internal rate of return (MIRR) and payback period all show that carrying of interest favours the FP over the MFO in a joint venture arrangement. Additionally, oil price and Petroleum Profit Tax (PPT) have the greatest impact on NPV in both models. Key Words: marginal field · operator · financial partner · 'carried' cost · net present value
Notwithstanding the fact that commercial oil discovery has been fifty-plus years in Nigeria; the Nigerian natural gas industry is known to be a developing industry. Thus, understanding the huge potential this industry presents to its economy, the Nigerian government has sought to implement policies that will bring about development in this industry. The paper seeks to examine the policies and the legal framework (if any), in order to ascertain to what extent the policies have been able to develop the industry and if not, why? In addition, the paper examines the adequacy or otherwise of the present legal framework. The paper finds that the successful and sustainable development of the natural gas industry hinges on the existence of adequate legal framework, as policies can only serve as aspirations and sought-after-goals without the backing of sufficient legal framework to support their implementation. The paper finds that in light of shale gas development in Nigeria's investors cum market geography, time is fast running for Nigeria as there is the urgent need to address the situation as Nigeria is gradually losing not just investors but her natural gas market as well.
Ogbuli, Andrew (Shell Petroleum Development Company of Nigeria Limited) | Kakayor, Omagbemi (Shell Petroleum Development Company of Nigeria Limited) | Bahry, Alia (Shell Petroleum Development Company of Nigeria Limited) | Adepoju, Yaqub (Shell Petroleum Development Company of Nigeria Limited) | Awa, Chukwunweike (Shell Petroleum Development Company of Nigeria Limited) | Balogun, Olalekan (Shell Petroleum Development Company of Nigeria Limited)
The management of uncertainties associated with ‘green fields' remains a challenge due to data paucity. In the context of rising development costs for oil and gas projects, integration of data from all available sources becomes imperative. This integration has been demonstrated to reduce identified subsurface uncertainties and risks.
Biostratigraphic data which comprises use of forams and fauna from ditch cuttings picked in several reservoirs in the field has been evaluated and is used to delineate the sequence stratigraphic boundaries which have been shown to be useful for building the framework for field correlation, thus the building of realistic static models.
The CAMOY Gas field located onshore Niger Delta basin was discovered in 1961 by CAMO-1 well. To date, a total of six wells have been drilled in the field. The field is split into two fault blocks by CAMO fault (an East-west trending fault) in the south. The minor block is penetrated by just one well, with the remaining five wells in the main block. A total of nine hydrocarbon-bearing reservoirs have been penetrated occurring between the depths of 6500 ftss and 11000 ftss.
Key subsurface uncertainties that impact on the development plan of the B4 gas reservoir have been identified, and they are associated with structure and stratigraphy. A range of static volumes were computed initially based on the original understanding of the underlying structural and stratigraphic uncertainties. However, by integrating biostratigraphic data in the reservoir correlation, the uncertainty associated with stratigraphy is reduced, leading to a more realistic range of volumes.
Following the building of a realistic 3D model and volume ranges, two wells have been proposed to be drilled to develop the reservoir. The placement of one of the wells closer to the CAMO fault has been optimized post application of biostratigraphic data in B4 gas reservoir correlation.
In the year 2000, TOTAL had announced that it would no longer continue routine flaring of associated gas on new oilfields development; and will make maximum efforts to stop continuous flaring on all existing installations. In 2004, TOTAL joined the Global Gas Flaring Reduction Partnership, A World Bank Initiative committed to reducing global gas flaring. The resolve of TOTAL's commitment to eliminating continuous gas flaring on all of its installations became overwhelming that between 1998 and 2005, TOTAL had reduced gas flaring by 40% despite, strong production growth within the same period.
In 2014, TOTAL set the objective to cut associated gas flaring by 50% from the 2005 baseline. Covered in this objective is the elimination of gas flaring on OML 102 - Ofon Oilfield, Nigeria; for which the Ofon Phase 2 Project have been endorsed and expected to achieve alongside other objectives. The project was scheduled to take off seven years after the phase 1 development which achieved its first oil in December, 1997 with no facilities for the utilization of the produced associated gas. Continuous gas flaring thus became unavoidable and thus served as the only way to safely dispose of the unwanted associated gas produced together with crude oil.
The eventual completion and realization of the seamless startup of Ofon phase 2 project, achieved in a context of high levels of local content coupled with the implementations additional energy efficient systems aimed at reducing global warming and energy consumption together is a clear demonstration of TOTAL's resolve to the sustainable development of the Niger Delta and the elimination of continuous gas flaring in Nigeria. In full compliance with Nigerian law, TOTAL has now eliminated gas flaring on OML102 – Ofon Oilfield. The elimination of gas flaring on the Ofon oilfield is also a significant milestone for TOTAL's environmental targets as it represents a 10% reduction in the Group's E&P flaring.
This paper presents the strategies and plans that were successfully implemented on the Ofon phase-2 project, which thus led to the realization of the seamless startup and consequently cascaded to the elimination of continuous gas flaring on the Ofon Oilfield Complex. The actions that were taken to drastically reduce the duration of the first oil startup which significantly reduced the initial startup flaring are also presented.