Where the natural drive mechanisms are inadequate, water-injection is commonly employed to supplement reservoir energy and improve sweep efficiency in conventional oil fields. In such applications, there is usually a strong positive correlation between field performance and injectivity/longevity of the water injectors. However, injectors are vulnerable to impairments, which can result in gradual injectivity decline and catastrophic failure. Therefore, robust field management and business planning require a good understanding of the impairment mechanisms of water injectors in general and, more important, reliable predictions of their injectivity behaviour and active lifetimes.
Following a review of common impairment mechanisms, this paper highlights the complexity and uncertainties of injector failure. It then exploits the two major impairment mechanisms of water-hammer and deep-bed filtration (DBF) to develop simple semi-empirical mathematical models for predicting the time-to-failure of vertical and slightly deviated water injectors. While water-hammer mobilises solid particulates native to the formation and deposits same in the wellbore, DBF entails external particulates suspended in the injection water and deposited in the reservoir. The mechanisms and impacts of these independent sources and deposition of formation-damaging particulates are covered.
Among other findings, sensitivity tests performed on the proposed models using realistic input data provide important insights into the mitigation and management of injector impairments caused by water hammer and DBF. To enhance the performance and longevity of water injectors, this study shows that these impairments can be mitigated through practical strategies such as (i) provision of long sumps (rat holes) as part of well completions; (ii) minimising the frequency and duration of emergency shutdown; and (iii) minimising the concentration of solid particulates entrained in injection water.
Finally, given the almost inevitability of injector degradation, it is recommended that realistic forecasting of oil and gas production associated with waterfloods should always account for potential injectivity decline and possible failure of applicable water injectors.
Ukaonu, Cyril (First Exploration & Petroleum Development Company) | Odubanjo, Teleola (First Exploration & Petroleum Development Company) | Lawal, Kazeem A. (First Exploration & Petroleum Development Company) | Eyitayo, Stella I. (First Exploration & Petroleum Development Company) | Ovuru, Mathilda I. (First Exploration & Petroleum Development Company) | Anyadike, Emeka (First Exploration & Petroleum Development Company) | Matemilola, Saka (First Exploration & Petroleum Development Company)
Sandstone formations that have potential to produce sand during the life of the well account for a significant fraction of global recoverable volumes of oil and gas resources. The economics, environmental and safety implications of sand problems are critical enough to justify good knowledge of the potential for sand failure and production. Reliable evaluation of potential sand production is required to identify the needs for and the specification of sand-exclusion equipment during the project execution phase.
To address these challenges, this paper presents a simple workflow that is premised on the petro-elasticity of the formation. Specifically, the proposed workflow uses cross plots of compressional sonic logs and density logs on reservoir-by-reservoir and well-by-well basis. From a petro-elastic standpoint, compressional sonic logs contain information on travel time required for sound waves to travel through the subject formation. The fundamental relationship between formation compaction (strength) and porosity has been explored to establish the trend of compaction, hence vulnerability of a sandstone formation to failure.
In illustrating the applicability of the proposed concepts and workflow, some field examples from the Niger Delta are presented. Using wells with known history of sand failure and production, the workflow has been applied retroactively. The methodology presented is very useful for establishment of a quick screening sand control requirement. From a qualitative standpoint, it is found that the performances of the proposed workflow are in reasonable agreement with the history of sand failure and production in the example wells.
Onwuchekwa, Chukwuma (The Shell Petroleum Development Company of Nigeria Limited SPDC) | Dennar, Linda (The Shell Petroleum Development Company of Nigeria Limited SPDC) | Ahmed, Suleiman (The Shell Petroleum Development Company of Nigeria Limited SPDC) | Bakare, Olatunji (The Shell Petroleum Development Company of Nigeria Limited SPDC) | Emelle, Chima (The Shell Petroleum Development Company of Nigeria Limited SPDC)
Reservoir models are calibrated with production and pressure data to provide some confidence in the prediction of future reservoir production using the models. The last two decades have witnessed the proposal of numerous computer-assisted history matching techniques to ease the laborious task of reservoir model history matching and the related task of uncertainty analysis. Although many of these proposals have proved not to be viable when tried on real (i.e field) cases, some, such as experimental design, are now routinely used in the petroleum industry for history matching and uncertainty analysis. One notable, but largely under-utilised, technique that has generated a lot of interest for application to history matching is adjoint-based optimization.
This paper discusses a field example of the application of the adjoint technique with experimental design to match the historical production and pressure data of a Niger Delta oil rim reservoir with a huge gas cap – the "SWX" reservoir in the "Beska" Field. The "SWX" reservoir, which is one of the few oil reservoirs in the gas-dominated "Beska" field, has been on production since 1992. A decision was to be made on the best time to commence gas cap blow down without jeopardising the life cycle hydrocarbon recovery from the reservoir. A properly history matched model of the reservoir was required for this decision.
Adjoint technique was deployed to assist with the history matching of the "SWX" reservoir which had previously proved difficult to history match. The technique was applied both in the model-maturation stage for improved understanding of the reservoir and the final stages of the history matching exercise to fine tune the history matches of some difficult-to-match wells. The exercise provided an opportunity to test the merits and limitations of the adjoint technique. The result of these tests will be discussed in this paper.
Gas identification and determination of Gas-Oil Contact (GOC) in reservoirs containing gas and oil can be a major challenge in laminated sand-shale sequences, where the presence of shales drastically affects the response of gamma ray, resistivity, density and neutron logs. Due to the resolution of these measurements, it becomes increasingly difficult to identify and quantify the gas reservoirs.
In a West Africa offshore well in a Cretaceous formation, using a Penta-Combo Bore Hole Assembly (BHA) with basic Formation Evaluation (FE) measurements, the use of additional services such as Nuclear Magnetic Resonance (NMR) and Formation Pressure Tester Logging While Drilling (LWD) services, significantly improved the confidence in interpretation of the reservoir fluids.
In the example well, though the size of the density-neutron crossover showed a reduction in the oil zone as compared to the gas zone to a certain degree, the actual position of the Gas/Oil contact and the reservoir fluid saturation were not certain. Using the traditional NMR porosity undercall in gas zones as well as the dual wait time (DTW) tranverse relaxation time (T2) distribution analysis, the gas zone was confirmed and the saturation of each of the fluids in the reservoir was accurately determined.
The NMR tool was programmed to acquire data in dual wait time (DTW) mode to calculate hydrocarbon saturation. The Magnetic Resonance Dual Wait Time (DTW) approach takes advantage of Longitudinal Relaxation Time (T1) contrast to solve for hydrocarbon saturation. "In light hydrocarbons, in a water-wetting reservoir, the hydrogen atoms in the hydrocarbon fluid relax slower than the nonmovable and movable water. By using two polarization or wait times (Tw), it is possible to calculate hydrocarbon saturation using magnetic resonance tools" (
Also, the gas hydrogen index effect was evident in the total porosity computation from NMR measurement. Significantly lower porosity was observed in the gas zone as compared to the oil zone. This was the first indication of Gas-Oil contact (GOC). Further analysis of the dual wait time T2 distribution gave a proper estimate of the saturation of the fluids in the reservoir.
The design of fiscal regime by oil producing government is usually tailored to capture high economic rent for the maximization of their citizen’s welfare. This has been the case of the royalty/tax system practiced in Nigeria, also known as the joint venture arrangement. The fiscal incentives under this system have been espoused to yield higher government take compared to the other fiscal systems practiced. Nevertheless, government participation in the joint venture arrangement through its NOC requires the government to provide funds for project development with cash call obligation. However, the NOC has defaulted, severally, in fulfilling its cash call obligations which has delayed several project developments. Thus, the recent government exit from JV cash call agreement is a favourable development that have created a vacuum as to how the joint venture operations would be funded and the impact on the economic metrics and the government take. It is against this background that we employed the use of a deterministic and stochastic cash flow model under 3 funding scenarios for the R/T system. Our empirical result shows that the impact of capital cost recovery yields a decrease in government take. The price of crude oil, royalty and profit petroleum tax were shown to have the highest impact on the government take. We concluded that despite the impact of the joint venture financing option on the government take statistics, the economic metrics yield higher profitability index thus making the project viable. Hence, we recommend that government considers a pseudo PSC or an overriding royalty funding arrangement in order to retain its participatory interest in the JV agreement without the obligation of cash call. Given that this funding option will impact the government take as shown in our analysis, the fiscal incentives used under this system should be reviewed and revised.
Kallel, Narjes, Oni, Olugbenga, Heiland, Juliane, De Gennaro, Vincenzo, Ramaswamy, Sunil, Arasi, Quadri, Campero, Manuel Flores, Odumboni, Idowu, Chemmarikattil, Rohan, Osauzo, Sam, Basu, Subhayu, Otevwemerhuere, Joseph
The use of gas injection and storage approach in enhanced oil recovery (EOR) is receiving increasing attention as an efficient solution to mitigate the effects of anthropogenic greenhouse gas emissions in the atmosphere, improve production by means of increasing static reservoir pressure, and allow optimized utilization of produced hydrocarbons as a function of actual consumption.
During gas injection a geological trap (i.e. active or abandoned reservoir) is used to store excess gas that can be eventually produced for future utilization. This process generates changes in pore pressure within the rock's porous space, affecting simultaneously the state of stress inside the reservoir and in its surroundings. These changes of the state of stress can be at the origin of instability mechanisms associated with fracturing inside and outside the reservoir and of reactivation of existing discontinuities (faults and fractures). If reactivation occurs within the caprock, this could lead to possible reservoir sealing failure and thus leakage of the stored gas at surface. Therefore, deformation of caprock and fault integrity must be assessed to properly manage containment performance and leakage-related risks. Given the intrinsic 3D nature of the problem, to ascertain the feasibility of injecting and/or re-injecting natural gas back into producing formations, it is essential to perform numerical simulations to capture the link between concomitant pressurization and /or depletion. The modelling is done with a 3D reservoir simulator and in-situ stresses changes are obtained by means of a 3D coupled reservoir geomechanics simulator.
A feasibility study of gas injection and storage in a producing reservoir was performed using coupled geomechanics modeling within an E&P software platform. The process started from single-well geomechanics analysis and then passed through 3D structural characterization and properties modeling, in-situ preproduction stress modeling, dynamic simulation, and, finally, injection modeling. Analyses were carried out using injection pressure modeled dynamically in an industry-standard reservoir simulator. This allowed various injection scenarios to be explored, providing a 4D characterization at various time steps in the future of the state of stress within the reservoir and its surroundings. Results highlighted the main risks, which are related to loss of sealing for the caprock and reactivation of induced faults, as well as uncertainties associated with input parameters.
This paper presents detailed theories and method of determining fault transmissibility and production history matching using the multi-tank material balance. This approach uses a two-step optimization process whose algorithm can be written as macros in spreadsheets. The upper-level (outer) stage optimizes the transmissibility and hydrocarbon initially-in-place while the lower-level (inner stage) optimizes the pressure of the support tank at each time step. This approach is validated using numerical simulation. This approach will be highly beneficial in effective reservoir management where little or no 3D seismic exists and for cases of sparse production data.
The dynamic format of the upstream oil and gas organizations, their resources, petroleum assets and market has created a huge gap and uncertainty in the entire upstream business ecosystem; resulting in challenges, opportunities and threats. These opportunities and threats exist both in the internal and external upstream business environment. Much focus by the upstream firms on strategic resource management and internal performance have made them to neglect uncertainty in the external environment causing them to build undiversified capabilities that cannot match strategic investment options in this modern era of crude oil price volatility, gas/energy options and heavy oil demand. The concept of dynamic capabilities has been utilized in various degrees by upstream and high tech firms to respond to a dynamic business environment by sensing, seizing and capturing opportunities and transforming resources. This article extends the dimension of this concept to include shorten time between sensing opportunities and transforming resources which entails optionality. In as much as many scholars have elaborated on the functions of dynamic capabilities, they have channeled little or no focus on strategic options and time to gain entrant to this options as a form of dynamic capabilities. This article therefore describes how upstream firms through optionality and strategic fit can capture valuable investment options with ease and in time, diversify and transform resources with agile flexibility and align both together; thereby enabling time value, evolutional fitness, organizational balance and environmental stability.
Sand production is one of the critical research subjects in the petroleum industry. In the oil and gas industry, the production of sand particles associated with the reservoir hydrocarbons has become one of the most common problems a well may experience during reservoir lifetime.
Sand production occurs in many fields across the world. This is easily seen in wells in the Niger Delta, Gulf of Mexico, Oman, Canada, Venezuela, Indonesia, Egypt, Trinidad and myriads of other places prolific to sanding. Managing sand production and ultimately its control in the oil and gas industry has been more or less a recurring problem. To fully understand the nature of sanding in an ingenuous way for sand control strategy, it is necessary to predict the conditions at which sanding occurs. Because so much have not been done in the implementation of the support vector machines for the prediction of the sanding onset in petroleum reservoirs, we are, for the first time, applying a robust approach, a binary classification problem approach for the prediction of sanding onset in petroleum reservoirs in the Niger Delta Region. By and Large, for the first time, the support vector machines (SVMs) classification approach, is used to identify whether sand will be produced or not in a hydrocarbon reservoir. The model presented in this paper takes into account different parameters (rock, fluid, geotechnical and other data) that may play a role in sanding. The performance of the proposed SVM model is verified using field data.
It is shown that the developed model can accurately predict the sand production in actual field conditions. The results of this study indicate that the implementation of SVM methodology can effectively help engineers to make a proactive sand control plan with insignificant impairment to hydrocarbon production from subsurface reservoirs.
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.