Awasthi, Amit (Shell Nigeria Exploration and Production Company) | Okonkwo, Arinze (Shell Nigeria Exploration and Production Company) | Afulukwe, Chuks (Shell Nigeria Exploration and Production Company) | Effiom, Oghogho (Shell Nigeria Exploration and Production Company)
Project B, consisted of five discrete subsurface elements; Remaining developed volumes, Infill opportunities, Resources in THIN-BED and Exploration prospects. These subsurface elements were at different levels of technical maturity and were planned into a single project maturity timeline with shared i(mpact on facilities. Based on level of technical maturity, two of the subsurface elements (THIN-BEDs, and Exploration prospects) were considered as requiring an appraisal plan to further mature their development options.
In anticipation of "lower for longer" oil price scenario, the appraisal strategy for the discrete elements was integrated and designed utilizing decision tree analysis. The appraisal strategy was developed for the immature subsurface elements, consisting of a variety of appraisal methods, each cost effectively geared towards fit for purpose data acquisition to mitigate the key uncertainties and enable further oil development in the field. Decision tree analysis for each of the immature subsurface elements, describing the possible outcomes with associated probability of success, was performed including fit for purpose economic analysis to understand & decide the value add and timing of appraisal.
This integrated appraisal strategy including decision tree analysis; provided the basis and strong logic to decide whether the appraisal is worthwhile and when is the most optimal time to do it.
This methodology demonstrates how the quality decision around field development planning could be made by using decision tree analysis to evaluate the value of the components, using associated uncertainty around estimated ultimate recovery. Furthermore, this analysis also is utilized to understand the timing of appraisal vis-a-vis the overall field/project development.
Chibueze, S. E. (Department of Petroleum Engineering, Federal University of Technology) | Ibeh, S. U. (Department of Petroleum Engineering, Federal University of Technology) | Onugha, I. N. (Department of Petroleum Engineering, Federal University of Technology) | Obah, B. (Department of Petroleum Engineering, Federal University of Technology)
Retrograde Gas Condensate reservoirs are economically valuable assets but constitute a complex system in its management and development. Condensate banking due to liquid condensation below the dew point pressure raises technical and economic concerns in unlocking reservoir potentials. As pressure decreases with production below the dew point, liquid drop out phenomena is inevitable. This has two major consequences for an operator. First, the condensation of liquid/condensates which are immobile and remains trapped in the reservoir pores due to capillary-induced interfacial tension creates a permanent formation damage/impairment signified by a reduction in gas relative permeability and productivity. Secondly, the bulk of heavier and valuable components are lost to the pores of the reservoir rock. In this study, the interactions among fluid flow and reservoir rock properties were integrated in modeling and simulation of a retrograde gas condensate reservoir undergoing gas cycling. Economic evaluations based on reservoir performance indicate that, with gas cycling, a 70% and 90% recovery in condensate and gas respectively with an Internal Rate of Return (IRR) of 41% is feasible.
A report is presented on natural gas dehydration performance of dehydration units in two different plants using a pre-inhibited glycol/antifoam/pH adjuster blend versus neat glycol with periodic injection of anti-foam and pH adjuster inhibitors.
To investigate the effect of using pre-inhibited glycol, two plants, each containing two gas dehydration trains (modules) were utilized such that while one train employed neat glycol with periodic chemical injection, the other employed the pre-inhibited blend with both trains running simultaneously. The two facilities were selected based on their history of poor dehydration and glycol regeneration performance and internal corrosion while using neat glycol. Performance was assessed based on resulting gas dew point, dissolved iron content, pH stability and glycol loss rate (in form of top-up frequency).
In all four KPIs selected for this study, the pre-inhibited blend out performed its counterpart significantly despite initial concerns that the fixed inhibitive properties of the blend may not be robust enough to address varying operational conditions. Glycol loss rates decreased by 67% and this led to a corresponding reduction in operating cost. Gas dew point was further depressed by more than 5°C thereby restoring the two facilities to within gas export specifications in compliance with Gas Sales Agreements (GSA). pH stability remained within the buffered zone of 8.5 – 10. As evinced by the decreased loss rates, foaming did not occur at this pH range as opposed to typical experience with neat glycol. Corrosion, being inherently more chronic than acute was not measured in this trial, although there was a progressive decrease in dissolved iron content with the pre-inhibited blend. These results imply that not only can dehydration performance be increased and operating costs decreased, but also that the traditional installation of pH adjuster and antifoam injection skids may prove unnecessary for future facilities
The insights made with this new pre-inhibited glycol blend approach presents strong evidence of an opportunity for significant reduction in both operating and capital costs for existing and future gas processing plants as well as a decrease in corrosion rates with prolonged plant life.
Green, Ovunda (World Bank Africa Centre for Excellence, University of Port harcourt) | Adeogun, Oyebimpe (World Bank Africa Centre for Excellence, University of Port harcourt) | iledare, Omowumi (Emerald Energy Institute, University of Port Harcourt)
Nigerian gas industry is gradually developing into an important sector of the nation's energy economy. Proved natural gas reserves is known to be substantially larger than oil potential in energy terms and it is estimated to be about 180Tcf.
Globally, natural gas has continued to displace other forms of fossil fuels for power generation due to its abundance, low carbon content and efficient technology. Gas, therefore presents the most viable option to bridge the existing gap between power generation capacity and demand in Nigeria. Despite Nigerian's huge potential in terms of gas resources and market, the gas sector is still plagued with perennial underdevelopment, principally caused by lack of clear fiscal regulatory framework and non market based gas pricing.
This paper, analyzes the economics of harnessing upstream natural gas for power generation using discounted cash flow model. Inputs for the model include a proposed PSC fiscal regime for offshore gas development; benchmark gas price for the power sector; cost estimates, production profile; discount and inflation rates. The estimated result in terms of the profitability indicator (NPV & IRR) and the discounted host government take (DHGT) shows the impact of the fiscal regime and gas price on profitability of upstream gas investment. IRR and NPV shows investment to be profitable at a base case gas price of $2.5/mcf. Further analysis carried out with respect to low, medium and high cost gas fields for associated and non-associated gas reveals that low and medium costs associated gas field and low cost non associated gas fields are profitable at a gas price of $2.5/mcf. Sensitivity analysis showed that high cost associated and non-associated gas fields are profitable at a gas price of $4.5/mcf. Stochastic analysis was also carried out to capture uncertainties associated with some variables used as input in the initial cash flow.
Adesanwo, Moradeyo (Baker Hughes Incorporated, USA) | Bello, Oladele (Baker Hughes Incorporated, USA) | Olorode, Olumide (Baker Hughes Incorporated, USA) | Eremiokhale, Obehi (Oriental Energy Resources Limited) | Sanusi, Sherif (Oriental Energy Resources Limited) | Blankson, Eyituoyo (Oriental Energy Resources Limited)
Increasing demand for cost-cutting measures has seen the petroleum industry taking advantage of new technology to accelerate production and increase ultimate recovery while maximizing reliability of the production system. Electrical submersible pump (ESP) technologies for in-well and subsea boosting systems have evolved to become a critical component in many production operations. However, ESPs are complex dynamical systems whose performance can be degraded by certain faults or events such as gas locking, changes in fluid characteristics, plugged pump, tubing leak and closed valve.
With the explosive growth of sensor data, it is no wonder that knowledge discovery has grown in importance in facilitating descriptive analyses (clustering) and predictive analyses (regression and classification) applications to ESP operations management. Interestingly, the development of appropriate algorithms to process ESP signals, detect events and prescribe optimal decisions given ESP real-time data and auxiliary, predictive observations have until now largely been overlooked.
This paper presents a decision support system for continuous ESP event detection and providing prescriptive analytics tool to analyze and manage ESP operation performance. The system includes a database management system, a real-time data management architecture, a real-time signals processing engine, forecasting system to forecast instance based on real-time data, outlier detection model, a sequence analyzer for event recognition, a prescriptive analytics to provide recommendations concerning the optimal alternative actions to be executed during events and a graphical user interface to visually analyze the flexibility and prescription model instance. The proposed procedure has been tested in a field to verify the functionalities of the system. The results show that the proposed methodology can be efficiently used in a wide range of electrical submersible pump system operation performance management and surveillance. The results demonstrate the importance of the proposed methodology and adapting it to ESP well production operations.
Fabbri, C. (TOTAL E&P Nigeria Limited) | Imeokparia, O. (TOTAL E&P Nigeria Limited) | Odeniyi, A. (TOTAL E&P Nigeria Limited) | Ibekwe, K. (TOTAL E&P Nigeria Limited) | Udoh, D. (TOTAL E&P Nigeria Limited) | Lanisa, A. (TOTAL E&P Nigeria Limited) | Fashanu, M. (TOTAL E&P Nigeria Limited)
In the Amenam-Kpono field, the main reservoir (R4) is characterized by vertically stacked deltaic sand bodies that are laterally extensive but with intercalated shale layers. Pressure maintenance is by both water and gas injection. Gas injectors are located on the crest of the anticlinal structure in order to re-inject the gas in the gas cap, while water injectors are located at the edge, injecting treated sea water into the aquifer. The R4 reservoir is divided into four disconnected hydrocarbon bearing flow units. The field has 35 development wells and more than 13 years of production (1st oil in July 2003).
Due to the layered nature of this reservoir, saturation logging is carried out regularly in order to check the contacts evolution at the well, even within the same flow-unit. Indeed, one of the main concerns since the start of water injection in R4 is understanding the communication between injectors and producers, which might lead to water cut increase and loss in productivity. This paper describes the measurements performed on an Amenam-Kpono well to evaluate a 20m additional perforation in flow-unit#1 (FU1). Two different measurements were carried out: saturation logging (oil saturation in the formation) and water flow log (measuring the water velocity around the tool). Integration of both results enabled the selective design of 20m additional perforation, leading to an oil incremental gain of 5800 bopd.
Gas portfolio development and the need to support Nigeria's Gas master plan is currently a high priority effort in government and international companies. Therefore, it is important to have a standardized approach for the development of the Gas Cap reservoirs. This guideline will provide a clear process to support the asset/study team in securing appropriate approvals from the government regulatory body (e.g. DPR) for the development of the gas cap resources.
Gas categorization guideline is adopted as a classification system for the company's gas reservoirs to help demonstrate the timing of availability of gas cap production. The classification is driven by the time remaining to produce the economic ultimate recovery from the oil rims associated with the gas caps and processing plants/evacuation ullage availability.
The objectives of the guideline are: To facilitate development planning and gas forecasting via a transparent picture on what the gas resources categories are. While existing fields mature, the development decisions regarding the oil rims become focused on ever reducing infill drilling targets. It is important to be aware how these decisions impact the availability of the gas cap production. The classification helps to provide clarity and transparency in this respect. This clarity aids to demonstrate the robustness of the Company's gas delivery promise. To help in defining standardized approach in getting approval for gas cap development from Department of Petroleum Resources (DPR). In defining this approach, a concise Gas cap release methodology is developed to guide asset and study teams in taking decisions on Gas cap development.
To facilitate development planning and gas forecasting via a transparent picture on what the gas resources categories are. While existing fields mature, the development decisions regarding the oil rims become focused on ever reducing infill drilling targets. It is important to be aware how these decisions impact the availability of the gas cap production. The classification helps to provide clarity and transparency in this respect. This clarity aids to demonstrate the robustness of the Company's gas delivery promise.
To help in defining standardized approach in getting approval for gas cap development from Department of Petroleum Resources (DPR). In defining this approach, a concise Gas cap release methodology is developed to guide asset and study teams in taking decisions on Gas cap development.
A clear workflow was developed for Gas Cap Development and subjected to company's internal assurance process.
Proper value assessment is done comparing the oil development and the company's gas requirement. Several sensitivities were carried out on the reservoir gas cap blowdown timing and the total reservoir NPV against the different GCBD timing ( GCBD Optimal Timing Sensitivity
GCBD Optimal Timing Sensitivity
Most operators’ business strategies had been to develop oil prospects, leading to several years of production from shallow formations. However, with growing domestic gas production and sustaining gas export in Nigeria, there has been a drive to develop gas reserves. This resolve to develop gas reserves to fulfill energy demands has led to exploring, appraising and developing deeper prospects in brown fields. Reaching these deeper horizons which are usually characterized by overpressured sands would mean drilling through shallower and most times depleted reservoirs due to several years of production. This poses very peculiar challenges as the margins between the pore pressure and the fracture resistance of the formation matrix is very low. This primarily determines the maximum allowable open hole that can be drilled for each section driving the well configuration in terms of hole sections and casing scheme. Drilling risks and uncertainties are increased with narrow margin drilling and these can range from lost circulation, equivalent circulating density (ECD) management, borehole stability, differential sticking, well ballooning, kicks among others. These are expensive drilling risks that are well articulated with mitigations put in place before drilling commences, as they are known to have cumulatively cost the oil and gas industry several billions of dollars.
This paper highlights the detailed design and planning towards a narrow margin drilling campaign on a gas field in the Niger Delta herein referred to as Alfyxx Field. It will also examine key experiences gained from drilling seven wells, Alfyxx 1-7; the adopted proactive strategies for different scenarios, encountered drilling challenges and recovery measures leading up to successful well delivery. The impact of unplanned challenges on cost and time in achieving the overall campaign objective is also discussed.
Olatunde, Folarin (Chevron Nigeria) | Adeyinka, Adeboye (Chevron Nigeria) | Lawal, Olumide (Chevron Nigeria) | Iyiola, Sunkanmi (Chevron Nigeria) | Faparusi, Dan (Chevron Nigeria) | Bodunrin, Abiodun (Chevron Nigeria) | Sustakoski, Richard (Chevron Nigeria) | Ebo, Henrietta (Chevron Nigeria)
Time-lapse seismic survey also known as 4D seismic has established itself as a useful tool for reservoir monitoring and has gained wide acceptance within the industry. Technological advancements in the area of acquisition and processing have further strengthened the case for its application.
The recent 4D seismic acquisition and interpretation in Agbami has proven to be an economically viable means of adding tremendous value to an oil field irrespective of the development stage it is in, and has been an excellent enabler for reservoir surveillance and resolution of subsurface uncertainties.
Effective management of a field such as Agbami requires a surveillance method which can provide insight into spatial fluid movements with time, which the traditional surveillance methods are unable to provide. This type of insight is required to support sound reservoir management and field development decisions which Agbami 4D seismic provides. The information from the Agbami 4D monitor has shed more light around the fault network architecture within the field and has validated and in some cases changed some of the initial assumption around the sealing nature of these faults.
Also, originally planned drilling locations and completion strategies have been modified based on the insight from the 4D seismic. The 4D seismic has also created value in the calibration of the reservoir simulation models and the location of bypassed oil within the field for future infill drilling. Forward modeling of expected seismic response based on proxy simulations helps to set realistic expectations of what can be seen in 4D seismic data. This paper discusses the acquisition, processing and interpretation of 4D seismic surveys in Agbami and how this information is being used to maximize the value in the field for the stakeholders.
This paper aims to address the question of how much economic value can be derived by the integration of modular refining in the development plan of a field qualified as marginal within the Nigerian petroleum industry context. Furthermore, the economic value sought by the integration will be weighed against the backdrop of current fiscal provisions and then compared with provisions for refineries that have historically been offered in successive versions of the PIB (Petroleum Industry Bill) – that of making the incentives for gas utilization projects found in Section 39 of the CITA (Corporate Income Tax Act) available for refinery projects.
For this evaluation, an onshore marginal field with reserve size 150MMBOE, and crude oil API of 38°API is assumed to be developed with an estimated CapEx of $900Million under a concession lease arrangement by a new entrant. The production from the field is to be monetized by the deployment of an optimally sized modular refinery configured to produce Gasoline, Kerosene, Diesel and Gasoil. A spreadsheet economic model is built which considers the upstream and refinery developments as fiscally separated and test the viability of the integrated project at the current terms and the historically proposed PIB2009 and PIB2012 terms. Sensitivities are performed around oil and product price, fraction of production refined, CapEx, OpEx.
Under the current terms, at $45/bbl and $2.70/mscf and assuming 100% production is refined on the asset, the integrated project yields an IRR of 12% compared with 15% under the proposed PIB2009. Furthermore, between the 2009 and 2012 proposals, the integrated project returns a lower IRR of 14% under the PIB2012 than the 15% observed for PIB2009. Sensitivity analysis further reveals that at any given oil price, the integrated project value improves with increased fraction of production utilized for refining. For example under current fiscal regime, at $45/bbl, NPV10 improves from