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Results
Abstract The production rate of a well is a functional relationship of system parameter, such as tubing internal diameter, gas/oil ratio (GOR), wellhead pressure, permeability, and skin among others. A sensitivity analysis is done by performance software to obtain the optimum production flow rate. Conventional method accomplished this by sequential optimization. Owing to its computationally expensive and time consuming nature, the need to determine the most profitable well design configuration while considering a number of system parameters simultaneously becomes very important. This procedure is called Multivariate optimization and of interest in this paper. A preliminary investigation of factors affecting the well's production rate was done. An eleven variable Plackett-Burman design approach was used to screen the main effect of both reservoir and tubing flow variables. Pareto chart was plotted to highlight the heavy hitters. A D-optimal design was also applied to minimize the volume of the confidence ellipsoid for the coefficient and provides the most accurate estimates of the model coefficients. A fully quadratic response surface was developed. Graphical analysis where used to show the optimum points as well as the optimum production rate. This model provides a tool for preliminary estimates of optimum production rate simultaneously with the effects of other variables.
Economic Investigation and Statistical Database Development for the Oil and Gas Industry
Dosunmu, Adewale (Shell-Aret Adams Chair in Petroleum Engineering, University of Port Harcourt) | Chimaroke, Anyanwu (Shell-Aret Adams Chair in Petroleum Engineering, University of Port Harcourt) | Evelyn, Ekeinde (Shell-Aret Adams Chair in Petroleum Engineering, University of Port Harcourt) | Oluwayomi, Ogurinde (Shell-Aret Adams Chair in Petroleum Engineering, University of Port Harcourt) | Paul, Fekete (Shell-Aret Adams Chair in Petroleum Engineering, University of Port Harcourt)
Abstract Nigeria's oil and gas industry is in its budding stage of development and thus requires high technological drive for growth and sustainability. Most operations done in the past have not been preceded by proper appraisal and review to ascertain if there might have been areas for optimization as well as improving on future operations. This has led to huge financial losses in oil business, of which Nigeria takes a substancial percenage of this loss. In this work, areas of business operations where these losses can be mitigated are identified through thorough economic investigation. The investigations are conducted under professional consultancy services, whose inputs are technology based and reliable at all times. In this investigation method, statistical data are developed that make history matches as well as identify regularly repeating trends in operations vivid. With the results from this analysis, new decisions can be made to better the outcome of future operations. Key areas for performance improvement are identified and optimized as well. Finally a database of various findings is developed to properly document useful data for future purposes by consultants as well as industry professionals. The Nigerian oil and gas business will benefit immensely from this project especially in management issues and in planning future business operations
- North America > United States (1.00)
- Africa > Niger (1.00)
- Africa > Nigeria (0.88)
INTRODUCTION A calculation method for predicting Bottom Movement and deposition of sand particles Hole Pressure (BHP) based on easily obtainable inside the well-bore could have adverse effect on wellhead parameter has been the preferred method in the petroleum industry. But, the the productivity as the movement causes predictive capability of the existing correlations increased erosion of the installed wellbore is a thing of concern to the oil industry operators. This is due to the inability of the equipment and additional pressure drop along existing models and correlations to account for the wellbore while the deposition causes sand to the presence of the sand particles in the flow stream; also the requirement for the well to be be collect in the low spot along the wellbore and shut-in for BHP predictions is counter thus constrict the flow of oil through the well at productive. These inadequacies were corrected in the proposed model. Results showed that the these points. Though sand removals techniques average pressure drop in the multiphase fluid has been successful in fluidizing the settled sand flow using the proposed model is higher than the pressure drops determined using existing models particles and removing them from the wellbore, and correlations. The effects of the fluid density, these operations are time consuming, expensive viscosity and velocity on the sand particles and require a knowledge of where the sand lifting were also investigated and results showed that the sand particle lifting was improved by deposits are.
3D Extended Reach Drilling in Soft Sediments with Precise Wellbore Placement for Optimum Recovery
Abhurimen, ThankGod (Hughes Baker) | Homburg, Heiko (Hughes Baker) | Foekema, Nico (Hughes Baker) | Ibrahim, Charles (Addax Pet. Dev.(Nig.) Ltd.) | Ogwumike, John (Addax Pet. Dev.(Nig.) Ltd.) | Olare, Jemine (Addax Pet. Dev.(Nig.) Ltd.)
Abstract The Adanga Field was discovered in 1974 and is located offshore Calabar in the central part of OML-123 in Nigeria territorial waters. Addax Petroleum took over operatorship of the fields in 1998, when the production from Adanga was just 2,000 BOE per day. Through introduction of new technology, field production increased to over 20,000 BOE per day by 2009. Poor productivity and increasing water cut is an issue in Adanga. Re-interpretation of 3-D seismic data and incorporating additional information from new wells 3-D reservoir modeling confirmed an economic hydrocarbon pool to the west of Adanga (ADW). Additional reservoir targets were identified in the Adanga South field. The plan was to develop these reservoirs from existing infrastructure. Unfortunately, the existing Adanga South platform had no remaining slot capacity to drill new wells without additional infrastructure investment. Upgrading the platform with additional drilling slots was deemed uneconomical, unsafe and will increase collision risk. The platform on adjacent field, Adanga South West, did have drilling slots available, so it was decided to investigate the feasibility of drilling extended reach wells from the Adanga South West platform to access these otherwise stranded reserves in the Adanga South field Challenges in drilling these wells include the weak nature of the formation which can pose difficulties to conventional directional drilling techniques, wellbore quality and ECD management. This paper describes the planning, engineering and execution of constructing two; complex, 3D, horizontal, extended reach wells drilled on the Adanga Field in 2010 to access locked-out reservoir in adjacent field. Using the experience from these two wells, the challenges of drilling complex, high angle wells in the weak sediments of the Niger Delta will be discussed along with how these wells were ultimately drilled and geologically positioned for optimum recovery.
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.99)
- Asia > Indonesia > Sumatra > Aceh > North Sumatra Basin > B Block (0.99)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta > Niger Delta Basin > OML 123 > Adanga Field (0.99)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
Abstract A Field development plan has been completed for a deepwater field located in gulf of guinea in water depth of around 1100 - 1400m offshore. The field is a confined turbidite channel system with some incised canyons and meandering channel complexes. The stacked nature of some of the reservoirs lends itself to combinations of drainage points. This can be harnessed to - reduce the well count by accessing multiple sands in one wellbore, accelerate production, and improve ultimate recovery from better reservoir management and/or development of reserves which cannot bear the cost of a dedicated conventional well. Smart well technology has been deployed in the field development plan to facilitate the realizations of these advantages and hence make the project economics more robust. In applying the technology, an integrated approach has been adopted all through the reservoir modelling, well planning and completion design sessions to ensure feasibility from the onset. A multi-disciplinary team and tools were fully deployed to ensure maximum gain realized in the smart well technology application. Based on the work done so far, the following justifies the appropriateness of the technology for the field: Smart wells overall value is in reducing the well count and overall CAPEX whilst maintaining the UR – Well count reduction by ∼20%. Well and reservoir management (WRM) Facilitation – Additional 10% to be gained from WRM via smart field implementation of appropriate level of smartness. This paper discusses the integrated approach and the tools that facilitated the process.
Abstract This paper illustrates how horizontal well interference tests in composite reservoirs can be analyzed using Tiab's direct synthesis (TDS) and curve matching techniques; providing insight into the three dimensioned nature of associated fluid flow. Resetroir heterogeneity is the reality and has been studied under various contexts including composite systems, multilayered systems, dual porosity systems, dual permeability systems, triple porosity systems; each with its corresponding flow anisotropy. A composite resen oir is one with multiple compartments; each having distinct rock and fluid properties separated by geologic discontinuities. Importantly, this reservoir system is encountered often in fields due to the geologic interplay between depositional and tectonic forces. For the first time using transform methods, a general customizable three dimensional point source semi-analytical solution for the drawdown response in composite clastic systems separated by a leaky fault is developed. This solution is then converted to line source for horizontal well observers by integrating along the producing well length while treating the leaky fault as a thin finite conductivity fracture separating two reservoirs with different rock properties. An arbitrary well orientation to principal permeability direction is adopted to obtain a general solution in an anisotropic system and this semi-analytical solution is achieved using a simple computer program which can generate type curves in a computationally cheap and effective manner. Sensitivity analysis conducted on generated interference responses with respect to areal permeability anisotropy, well position, reservoir dimensions, dimensionless fault conductivity and mobility ratios in composite clastic reservoir systems reveals that the response is a convoluted function of resetroir properties from both compartments and the separating semi-permeable medium. It is observed that the intersection time between the long-time approximation of both observer pressure drawdown and observer pressure derivative is unique - from which producer hydraulic diffushdty could be obtained. Tiab direct synthesis (TDS) of resetroir parameters from the resulting equation is examined. From resulting type curves, it is observed that there exists a limiting fault conductivity, compartment-permeability contrast and well-fault distance among other reservoir parameters that could register on the drawdown response signature. The result of this work is attractive where sand juxtapositions separated by leaky faults in the reservoir is suspected to allow flow from adjacent fields, especially if an existing well in the other compartment can be used as an observer.
- North America > United States > California (0.29)
- North America > Canada > Alberta (0.28)
- Europe > Macedonia > Resen > Resen (0.24)
- Geology > Structural Geology > Tectonics (0.68)
- Geology > Structural Geology > Fault (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Reservoir fluid properties are very important in reservoir engineering computations such as material balance calculations, well test analysis, reserve estimates, and numerical reservoir simulations. Ideally, this property should be obtained from actual measurements. Quite often, this measurement is either not available, or very costly to obtain. In such cases, empirically derived correlations are used in the prediction of this property. This work focuses on the use an artificial neural network (ANN) to address the inaccuracy of empirical correlations used for predicting oil formation volume factor. In this modeling approach 802 data set collected from the Niger Delta Region of Nigeria was used. The data set was randomly divided into three parts of which 60% was used for training, 20% for validation, and 20% for testing. Both quantitative and qualitative assessments were employed to evaluate the accuracy of the new Artificial Neural Network to the existing empirical correlations. The ANN model outperformed the existing empirical correlations by the statistical parameters used with a lowest rank of 0.855 and better performance plot.
- Asia (1.00)
- Africa > Nigeria > Niger Delta (0.62)
Abstract Petroleum Fiscal System (PFS) is a key determinant of investment decision in the exploration and production (E&P) of oil and gas. It describes the relationship between the host governments, the investors, and community stakeholders with respect to how costs are recovered and profits are shared equitably. A comparative economics of the performance of fiscal regimes becomes imperative as it affects stakeholders in making informed decisions on the oil and gas business investments worldwides. This paper evaluates the structure, conduct and performance of PFS in Gabon, Equatorial Guinea, Angola and Nigeria in the Gulf of Guinea (GOG). These countries hold about 90% of the GOG proved reserves. Economic analysis of the same E&P phases using hypothetical field and cost data under the different PFS are presented and discussed for comparative PFS performance evaluations. Comparison of the effects of production delay, front loaded government take and taxation shows that petroleum sharing contract fiscal terms and instruments in Gabon, Equatorial Guinea, Angola and Nigeria are relatively competitive. We found that as the risk in deepwater investment increases with water depth, return on investment rises in these GOG countries. Monte Carlo simulation process incorporated to account for risk and uncertainties reveal early discounted payout for investors in these GOG countries with significant degree of ceteris paribus.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Africa Government > Nigeria Government (0.68)
Reducing Field Development Risk in Marginal Assets through Probabilistic Quantification of Uncertainties in Estimated Production Forecast - Tsekelewu Case Study
Obeta, Chukwudi. C. (Sahara Energy Field Limited) | Ugonoh, Mohammed. S. (Sahara Energy Field Limited) | Ajayi, Olajumoke. C. (Sahara Energy Field Limited) | Sijpesteijn, Casper Kaars (Sahara Energy Field Limited)
Abstract Tsekelewu field North of Niger Delta consists of twin structural culminations and two well penetrations. Because it is poorly appraised, fluid distribution within the structure is not well defined, with almost all encountered hydrocarbons found in Oil-Up-To configurations. The limited available PVT data is of questionable quality, and there is no core and SCAL data to calibrate the evaluated petrophysical parameters. Moreover, the lateral extent of Opuama channel which eroded the Eastern limit of the field is not well defined by seismic, thereby allowing part of the trapping configurations to be only inferred. These aforementioned data gaps introduce significant uncertainties in fluid levels, lateral reservoir and structural continuity, fluid properties and distribution, geologic and petrophysical properties, presence and size of available aquifer for the Tsekelewu marginal field. Due to the nature of marginal field development, often key development decisions are based on a single deterministic scenario of volumetric estimate and production forecast. This poses additional risk to marginal field development. In order to provide a robust framework that adequately frames the spectrum of subsurface uncertainty, we applied Experimental Design methodology using a proxy model to probabilistically evaluate resource volume, rank and risk opportunities, tested various development concepts and generate production forecast for the Tsekelewu Field. This paper emphasizes the limitations of a single realization and makes a case for adopting a model that reduces risks associated with investment decisions in marginal fields. The significant difference between deterministic STOIIP estimate and forecast, and the P50 realizations from model probability density function highlights the value in investigating all possible outcomes. This study provides the basis for the forward looking strategy for Tsekelewu Field Development.
- North America (0.93)
- Africa > Nigeria > Gulf of Guinea > Niger Delta (0.66)
- Africa > Nigeria > Niger Delta (0.24)
Abstract As the high demand for fossil fuel pushes the frontiers of oil exploration and production into more hostile environments, issues associated with flow assurance have become increasingly important. This is especially true of paraffin wax precipitation and deposition in areas of reduced temperatures, such as the Polar Regions and in deep sea environments. In order to reduce costly remedial operations aimed at removing pipe/tubing blockages resulting from wax deposition, it is essential to predict when, where and how much paraffin wax is deposited during the working life of oilfield installations. In this study, a computer application model capable of predicting wax precipitation and deposition in oilfield installations under various conditions of flow was developed. Thus, a computational flow dynamics (CFD) program named "WD-Predictor" using C++ language was designed and developed with mathematical models that approximate the physical behavior of wax crystallization and deposition systems such as; Property Transport Models (Energy, Momentum and Mass), Thermodynamic Equilibrium Model and Wax Deposition & Erosion Model. The mathematical models developed were discretized while numerical solutions to the discretized models were then developed using appropriate algorithms and pseudo-codes. The "WD-Predictor" was used to estimate the Wax Appearance Temperature (WAT) of three crude samples. The results obtained were compared to an experimental results published; Exp.WAT for oil sample 1 was 87.800°F and Predicted was 89.888°F, for oil sample 2- the Exp. WAT was 114.35°F and predicted was 115.76°F and for oil sample 3, Exp. WAT was 72.950°F while Predicted was 70.620°F. Again, WD-Predictor results were compared with the experimental data extracted from Cordoba and Schall (2001). Above all, WD-Predictor output on wax deposition thickness was also compared with the enthalpy-porosity model proposed by Banki et al. (2008) and in all the WD-Predictor showed consistence in results, in line with these published experimental results. Finally, WD-Predictor was validated with a well-tested simulator PROSPER™ on pressure and temperature profiles using Beggs & Brill Correlations.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)