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Title: Integrated evaluation of wet gas reservoir : minimizing volumetric uncertainties using dynamic analysis
Author: Saidu, B.
ISNI:       0000 0004 8508 7933
Awarding Body: University of Salford
Current Institution: University of Salford
Date of Award: 2019
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There is a growing research effort to understand the most reliable approach in estimations of oil and gas reserves, through different procedures such as the volumetric, Material Balance, Reservoir Simulation, Decline Curve Analysis (Production performance analysis), which depends on the understanding of the physical flow characterization of the formation, production data, and recently dynamic nature of reserves. While most researchers were motivated by static nature of dry gas reserves and hence, their reserve estimations consider parameters typical of such reservoirs, formations where associated gas is found has continued to be a challenge particularly in sandstone reservoirs. In this study a novel approach of adopting integrated experimental and analytical techniques, using digital core flooding system to establish dynamic properties of the reserves was used in combination with analytical techniques including Volumetric, Decline Curve Analysis, Reservoir simulation and Material balance. Experimental study was conducted in phase I to determine rock properties, such as effective porosity, permeability and distribution of pore size, generally regarded as petrophysical properties, the core characterization measurement of the dimensions and weight were performed using the Vernier calliper, weight measurement balance. In Phase II PVT (Pressure, Volume and Temperature) analysis for gas composition and fluid properties were also carried for a wet gas field case study (Ogba Essale). A sub set of the sample was flashed from reservoir condition to atmospheric condition (758.31 mmhg and 82.4 f). The products (i.e. gas and oil) were analysed by gas chromatographic technique and then mathematically recombined to obtain the reservoir fluid composition. Constant composition expansion (CCE) test, Constant volume depletion (CVD) test were performed at the reservoir temperature of 224.6 f. multi-stage separation test was performed at the specified surface processing condition, the results were subsequently inputted for reserve evaluation into various method Phase III Involved Modelling and computer simulation Static geologic models in Petrel and Reservoir simulation models in Eclipse 100 and 300 were built and utilized to estimate the hydrocarbon volumes. Similarly, in this phase Declining Curve Analysis using Oil Field Manger (OFM), Material Balance and Volumetric calculations was carried out. Phase IV focused on Single Phase flow of Buff Bera using Navier-Stokes equations and Darcy`s law to describe single-phase gas transport and free gas at the pore spaces. The models were developed using water salinity representation of the wet gas field in the case study, to simulate the performance of the natural gas reservoir in assessing the performance of production from natural gas reservoir. Phase V: Core flooding for two-phase liquid movements under unsteady state or steady state circumstances and single-phase gas steady-state experiments, was conducted. Phase VI involved the application of COMSOL-Physics, constitute the creation of a pore-scale finite element mesh of sandstone core samples from SEM images and based on the numerical simulation of sandstone at a pore-scale level based on experimental results iii Phase 7: Results analysis and discussions: The findings indicated from the characterization (phase I) indicated for porosities of the respective core samples: Buff bera 24.55% and 20-22%, Castle gate 29.31% and 27-29%, Boise 30.35% and 28%, Bandera Grey 19.67 and 19-21%, and Grey Beira 20.18% and 18-21% for experimental and factory values respectively. While permeabilities values indicated Buff Beira 458.1mD and 350-600mD, Castle gate 1434.8mD and 1300-1500mD, and Boise 2196.4mD and 2000-4000mD for experimental and factory values respectively, the porosity and permeability values by the experiment deviated slightly from the factory porosity values. The experimental result showed good agreement with the literature data under dynamic conditions, subsequent data of the Buff Berea experiment result was implemented into COMSOL multi physics software to characterize gas transport of singlephase flow at pore scale level. Also, for this study, the Buff Bera values of porosity and permeability were imputed for all the reservoir evaluation technique except for Reservoir simulation of which porosity was estimated from the bulk density and sonic logs using average grain density of 2.65g/cc, 1.00g/cc and 0.85g/cc for fluid density, 53msec/ft. for average grain velocity and 189msec/ft. For pore fluid velocity, the net sand of the reservoirs was estimated by applying Petro-physical cut-off (vsh=0.52, porosity=0.12). The results from the aquifer salinity confirms that the higher the salinity of the aquifer the higher the natural gas production and the lower the produced water as seen in the gwr vs time graph. there was a production increase of about 50% when 0 wt% salt encroached the reservoir compared to when 10 wt% Nacl. With this leading finding, a better characterisation of the natural gas reservoir will be carried out for adequate evaluation of the performance of the reservoirs in the phase II of the study. Consequently, 75.9132 MMSTB of oil and 2,188.54 BCF of gas was obtained from reservoir simulation, do nothing case: an additional recovery for the field is about 30.23MMSTB and 27.8BSCF of oil and gas respectively. case 1: an additional recovery for the field was about 37.21MMSTB and 26.0BSCF of oil and gas respectively. STOOIP of 1548.297365 MMSTB and GIIP of 3007862.483 MMSCF from volumetric, EUR of 52261BSCF gas and EUR of 452.6MMSTB from decline curve analysis, and GIIP of 370.47MMSCF and STOOIP of 377.26MMSTB from material balance. the volume of initial hydrocarbon obtained from material balance analysis and static model volume estimates are comparable and within 2 -6% difference. The declining curve analysis and production performance analysis were carried out and compared with a slight variation of the end volumes. This study has utilised dynamic reservoir data integrated with various models, which can be valuable in improving reserve estimation using multiple models compared to single models adopted by many research and industry practices.
Supervisor: Not available Sponsor: PTDF
Qualification Name: Thesis (Ph.D.) Qualification Level: Doctoral
EThOS ID:  DOI: Not available