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Results
Relative Rock Strength Determination from Well Logs - Comparison of Deepwater Fields, Offshore Nigeria.
Jenakumo, Timipere (Shell Nigeria Exploration & Production Co.) | Adoghe, Leo-Andrew (Shell Nigeria Exploration & Production Co.) | Aniekwe, Osita (Shell Nigeria Exploration & Production Co.) | Nwosu, Chike (Shell Nigeria Exploration & Production Co.)
Abstract Elastic constants (Poisson ratio, Young's and Bulk Moduli) and acoustic velocities are often used to specify the strength of rock materials. An understanding of reservoir rock strength and geomechanical issues related to drilling and producing from unconsolidated formations are essential for well completion and injection design as well as production performance and optimization of recovery. Typically, laboratory tests such as unconfined compressive strength, triaxial strength test from cores provide stress and strain parameters from which the elastic constants are derived, and rock strength is determin d. In the absence of these laboratory tests, this study has used well logs (density, compressional and shear wave velocity) to derive the dynamic rock mechanical properties and assessed the relative rock mechanical strength for four select Nigerian deepwater fields. This work investigates the possible impact of formation strength of four deepwater fields with respect to causes of drilling, completion and injectivity issues. Water injector wells in Field B1 are seen to be quite successful, whereas this is not the case in field A1. The studyresults provide some insight into the relative degree of consolidation between these fields. Comments on the completion practices and injection into similar rocks in these fields will be based on the determined relative rock strength.
- Africa > Nigeria (1.00)
- Europe > Norway > Norwegian Sea (0.24)
- Africa > Nigeria > Niger Delta > Niger Delta Basin (0.99)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 186 > Field A Field > Silurian Tanezzuft Formation (0.98)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation (0.98)
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.
Sanding Prediction using Rock Mechanical Properties (A Parametric Study)
Joseph, A.. (Department of Petroleum and Gas Engineering, University of Port Harcourt) | Akubue, L. C (Department of Petroleum and Gas Engineering, University of Port Harcourt) | Ajienka, J. A (Department of Petroleum and Gas Engineering, University of Port Harcourt) | Oriji, A. B (Department of Petroleum and Gas Engineering, University of Port Harcourt)
ABSTRACT Sand production is described as the production of load bearing sand grains along with the produced reservoir fluids. Problems associated with it include: blockage of tubular, formation damage, casing collapse, erosion of facilities, leakages and spills, environmental issues and disposal problems. Predicting the potential of sand incidence is an important decision that petroleum engineers must make, at the time of well completion to avoid unnecessary sand control expenses. In this work, a parametric study was made to investigate the impact of various mechanical rock properties using Omar Abdulaziz Almisned's prediction model. Different diagnostic plots were made to establish unique trends for five cases using five different rock parameters and compared with the critical pressure at various depths. It was observed that the critical pressure increases with the increase in Shear modulus, Young's modulus and bulk compressibility, but decreases with the increase in poisson's ratio and bulk modulus. In addition, it was observed that the plot, (1/k)/(ts/tc)x10, gave a close and consistent trend. This parametric combination has the same dimension as rock compressibility. This model will serve as a useful tool to estimate critical well pressure causing sand prediction, predict sand production and can also be used to perform parametric comparison of different mechanical rock properties.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.31)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Safaniya Field (0.99)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Safaniya Field (0.99)
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 Accurate reservoir performance prediction m a structurally complex brown field is very important for generation of reliable production forecasts, location of possible by-passed oil estimation of reserves and optimal well/ reservoir management. Reserves estimation is one of tire key functions of Petroleum Engineers and it requires an integrated approach for tellable estimates to be made. The traditional techniques include Decline curve analysis, Material balance. Volumetric. Analogues and Numerical Reservoir simulation. Reservoir X is a structurally complex reservoir nr Field Y in the Niger Delta Basin. It came on stream in 1970 with 3 wells. Eight additional wells started production between 1972 and 1990. Five infill wells were drilled and completed between the years 2000-2005. However, due to operational and technical reasons (which are beyond the scope of this paper), 2 of these wells are yet to be put on production Over the years the reserves associated with these 2 wells have been estimated by analytical means (Volumetric and Material balance methods). However, there was the challenge of investigating the impact of fluid saturation changes around these wells, occasioned by the production fiom offset wells, on the reserves estimate obtained fiom material balance techniques These challenges necessitated the full field 3D integrated reservoir modeling The reservoir contains 9 blocks in which 8 are densely faulted. The material balance analysis, being, at most, a onedimensional model, was deficient in robustly assessing the subsurface uncertainties which includes fault sealing potential and fluid contacts movement. This paper discusses the techniques employed in building die static and dynamic models and shows a comparison of the reserves estimate results fiom analytical techniques versus 3D dynamic estimates.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (6 more...)
Abstract With global energy demands on a steady increase, it is important to ensure hydrocarbon production optimisation and sustainability while minimising production process impact on the environment. As a result, technologies and processes that improve response to production challenges and guarantee optimisation and sustainability of production and products utilisation, especially associated gas, have become more relevant in the oil and gas industry. The Integrated Production System Modelling (IPSM) tool is a means of simulating actual production systems and assessing their responses to changing production scenarios, challenges and the impact of various solutions on production systems before effecting the changes in the field. IPSM was used to assess the options of ensuring gas availability to meet the minimum turndown ratio of the associated gas gathering (AGG) low pressure compressor and ensure optimal oil production from a field in the Niger delta of Nigeria. Declining gas production from the producing oil wells in the field poses the challenge of keeping gas production above the minimum required turndown ratio for the compressor to run. A multi-disciplinary review and production system optimisation identified the options of re-routing either of two producing oil wells with significant gas production rates from a nearby field to the production facility of the field of interest to ensure the minimum required gas is always available. The impact of re-routing each of the proposed wells on the overall production system efficiency was analysed using IPSM with a view to optimising oil and gas production without compromising recovery from the wells in the field of interest. The results from the analysis indicate that IPSM is a robust tool for analysing the various options and optimising the required solution. The impact of the different options on overall system health was quantified and greatly enhanced the business decision making process with overall benefit of provision of required LP gas to run Field Y compressor, safeguarding the invested fund of building the AGG plant in addition to a projected 5MMscf/d sales gas.
- Africa > Nigeria (1.00)
- North America > United States > Texas (0.68)
- South America > Brazil > Amazonas > Solimoes Basin > Urucu Field (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Lobo Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OML 118 > Bonga Field (0.99)
Abstract There is an increasing need to limit the use of chemical treating agents during oil and gas production and to search for safer and cost effective ones mainly due to environmental constraints. Therefore the use and performance of demulsifiers have to be improved from the application and cost as well as from the environmental issues. This means that new formulations must be less toxic and efficient compared to the general classical chemical families of demulsifiers which contain toxic molecules like phenol groups. This paper is on the performance and the comparison of four chemical demulsifiers (local and foreign) on their demulsification of four crude oil emulsions of different asphaltene contents from different oil wells in the Niger Delta. The chemical families of these demulsifiers were screened with effective separation ability of different surfactants using classical "Bottle test". The Bottle test helped to determine the type of demulsifier that will most effectively break the emulsion of the crude samples. The basic aim of this screening was to compare and rank the efficiency of the various demulsifiers both local and foreign (V4404 of Nigeria, 92LTM174 of USA, EN/82/2 of France and DS 964 of Canada) in terms of percentage (%) volume of water that will be separated out of the samples. The results showed that the viscosity of the emulsions increased as the water content increased with an assumption that only oil and water were present. The nature of the emulsions were subject to changes, therefore no treatment method was conclusively generalized as best for every emulsion problem. Finally from the preliminary screening, the result also revealed that V4404 a local demulsifier exhibited very interesting performance and was also environmentally friendly compared to the imported ones.
- North America (1.00)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta > Niger Delta Basin > OML 123 > Mimbo Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Bight of Bonny > Niger Delta > Niger Delta Basin > OML 123 > Akam Field (0.99)
- Africa > Nigeria > Bendel > Niger Delta > Niger Delta Basin > OML 98 > Ogharefe Field (0.99)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Best Practices in Seismic Data Processing- A Case Study From Ghana
Adigwe, Helen-Nellie (Sahara Energy Field Limited Nigeria) | Shoroye, Adeyemi (Sahara Energy Field Limited Nigeria) | Ajayi, Jumoke (Sahara Energy Field Limited Nigeria) | Vasconcelos, Rui (Sahara Energy Field Limited Nigeria) | Barnett, Peter (Sahara Energy Field Limited Nigeria) | Elbassiony, Ahmed (Sahara Energy Field Limited Nigeria) | Matsourak, Vira (Sahara Energy Field Limited Nigeria) | Masse, Michel (Sahara Energy Field Limited Nigeria) | Cavalin, David (Sahara Energy Field Limited Nigeria) | Hussein, Waleed (Sahara Energy Field Limited Nigeria) | Salah, Magdy (Sahara Energy Field Limited Nigeria)
Abstract Today's Exploration seismic data quality requirements for early detailed geophysical reservoir characterization, baseline time-lapse surveys and fluid characterization have been largely satisfied by the technological advances in seismic acquisition. This then followed-up by first pass conventional processing sequence, including inadequate QA/QC and project management renders obsolete the time and effort put into the planning and executing of the seismic survey in the first place, as the processing results will be no better than a conventional exploration shoot, where the main objective typically is coverage and structural definition. This paper deals with experiences from a recent 3D acquisition, first pass processing which was followed by a focussed reprocessing sequence. The latter performed by a multidisciplinary team comprising various levels of expertise from client and contractor. This paper will discuss how the more relevant advances in the application of concepts, models, techniques, workflows and decision processes related to the supervision of seismic data processing, with focus on initial detailed scope definition, contract management plan, team composition and communication protocol, detailed technical meetings and deliverables, QA/QC processes and sign-off, produced a better output in today's seismic processing project..
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Volve Field > Smith Bank Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Volve Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 046 > Block 15/9 > Volve Field > Hugin Formation (0.99)
- (6 more...)
Lithofacies Estimation by Multi-Resolution Graph-Based Clustering of Petrophysical Well Logs: Case Study of South Pars Gas Field of Iran
Aghchelou, M.. (National Iranian South Oil Company) | Nabi-Bidhendi, M.. (Institute of Geophysics, University of Tehran) | Shahvar, M. B. (Petroleum University of Technology Research Center of Iran)
Abstract South Pars gas field is the largest gas field of the world, located at the boundary between Iran and Qatar in the Persian Gulf in a distance of 100 kilometres from the southern shores of Iran. Its gas-in-place is estimated to be about 14.2 trillion square meters while the amount of its condensate-in-place might be around 18000 million barrels. South Pars gas field also has an oil layer containing about 6 billion barrels oil-in-place. Since South Pars field is a heterogeneous carbonate system, lithofacies characterization is the best solution for overcoming the problem of heterogeneity in determining the petrophysical properties of the reservoir rock, reservoir modeling and identifying producing zones, but coring which is the most robust method of lithofacies identification is very expensive, time consuming and is limited to few number of wells. Therefore this study is focused on determining the lithofacies of the understudy formations from available well logs. For this purpose multi-resolution graph-based clustering (MRGC) technique which is a dot-pattern recognition method based on non-parametric K-nearest neighbor and graph data representation is applied on sonic, density, neutron porosity and gamma ray well logs to define electrofacies similar to core-derived facies that are determined as twelve distinct ones. The cluster of the MRGC method is defined from model that has specific character associated with the group of lithofacies. Then, Kernel representative index is used to calculate the optimal number of clusters. Small facies groups are formed based on utilizing the neighboring index to determine a K-nearest neighbor attraction for each point. At last, final clusters are constructed by combining the small clusters which lead to identifying 12 facies of South Pars gas field from well logs by high accuracy. Method used in this study has obviated the need of extensive coring in the South pars field which caused saving large amounts of money and time.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.70)
- Asia > Middle East > Iran > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > South Pars Field > Upper Khuff Formation (0.99)
- Asia > Middle East > Iran > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > South Pars Field > Upper Dalan Member (0.99)
- Asia > Middle East > Iran > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > South Pars Field > Sudair Formation (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)