Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
The amount of tight formations petrophysical work conducted at present in horizontal wells and the examples available in the literature are limited to only those wells that have complete data sets. This is very important. But the reality is that in the vast majority of horizontal wells the data required for detailed analyses are quite scarce.
To try to alleviate this problem, a new method is presented for complete petrophysical evaluation based on information that can be extracted from drill cuttings in the absence of well logs. The cuttings data include porosity and permeability. The gamma ray (GR) and any other logs, if available, can help support the interpretation. However, the methodology is built strictly on data extracted from cuttings and can be used for horizontal, slanted and vertical wells. The method is illustrated with the use of a tight gas formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). However, it also has direct application in the case of liquids.
The method is shown to be a powerful petrophysical tool as it allows quantitative evaluation of water saturation, pore throat aperture, capillary pressure, flow units, porosity (or cementation) exponent m, true formation resistivity, distance to a water table (if present), and to distinguish the contributions from viscous and diffusion-like flow in tight gas formations. The method further allows the construction of Pickett plots without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of many tight formations currently under exploitation.
It is concluded that drill cuttings are a powerful direct source of information that allows complete and practical evaluation of tight reservoirs where well logs are scarce. The uniqueness and practicality of this quantitative procedure is that it starts from only laboratory analysis of drill cuttings, something that has not been done in the past.
Napalowski, Ralf (BHP Billiton) | Loro, Richard (BHP Billiton) | Anderson, Calan Jay (BHP Billiton) | Andresen, Christian Andre (ResMan AS) | Dyrli, Anne Dalager (ResMan AS) | Nyhavn, Fridtjof (ResMan AS)
This paper describes the interventionless approach that was successfully executed during the Pyrenees early production phase to identify the timing and location of water breakthrough. Chemical inflow tracers were installed in key production wells within the lower completion along the horizontal production sections. Results from this work have supported the reservoir simulation history matching process and confirmed the performance of the inflow control devices (ICDs). These data in conjunction with the real time rate information from subsea multiphase meters has allowed proactive reservoir and production management that has contributed to the early identification of additional infill opportunities.
Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves.
Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects.
This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.
Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during well drilling, completion, stimulation and production (Dusseault, 1993). The low permeability gas reservoirs can be subject to different damage mechanisms such as mechanical damage to formation rock, plugging of natural fractures by invasion of mud solid particles, permeability reduction around wellbore as a result of filtrate invasion, clay swelling, liquid phase trapping, etc (Holditch, 1979).
In general, for tight sand gas reservoirs, average pore throat radius might be very small and therefore it may create tremendous amounts of capillary forces. Capillary forces cause the spontaneous imbibition of a wetting liquid (in this case water) in the porous medium in the absence of external forces such as a hydraulic gradient (Bennion and Brent, 2005). This causes significantly high critical water saturation (Bennion et al., 2006). Two forces drive capillary flow (Adamson and Gast, 1997). The first is the reduction in the surface free energy by the wetting of the hydrophilic surface (wettability). In hydraulic fracturing, water in the fracturing fluid wets the surface of the pores in the rock, resulting in a decrease in the surface free energy of the pores. The other force that drives capillary flow is the capillary pressure.
Tight gas reservoirs might be different in term of initial water saturation (Swi) compared with critical water saturation (Swc), depending on the geological time of gas migration to the reservoir. Initial water saturation might be normal, or in some cases sub-normal (Swi less than Swc) due to water phase vaporization into the gas phase (Bennion and Thomas, 1996). The initial water saturation might also be more than Swc if the hydrocarbon trap is created during or after the gas migration time. A sub-normal initial water saturation in tight gas reservoirs can provide higher relative permeability for the gas phase (effective permeability close to absolute permeability), and therefore relatively higher well productivity (Bennion and Brent, 2005).
Quinlan, Timothy Michael (Schlumberger) | Sibbit, Alan Matthew (Services Techniques Schlumberger) | Rose, David Alan (Schlumberger) | Brahmakulam, Jacob V. (Schlumberger) | Zhou, Tong (Schlumberger) | Fitzgerald, John Barry (Steve Kimminau Consulting) | Kimminau, Stephen John
Carbon Dioxide (CO2) sequestration and enhanced recovery projects require the evaluation of rocks containing mixtures of CO2, water, and gaseous or liquid hydrocarbons. Pulsed neutron logs of various designs and measurement types have been used since the 1960s to evaluate formations containing gaseous hydrocarbons, but they were not originally designed or characterized specifically for quantitative CO2evaluation. Computer modeling, test pit data, and field examples are presented in this work to highlight the issues of CO2 evaluation and to compare these with gaseous hydrocarbons.
Pulsed neutron tools emit 14 MeV neutrons from an accelerator source, but a wide variety of timing sequences, detector types, source-detector spacings, and signal processing techniques are employed by the industry to extract formation description parameters from the recorded counts. For the non-specialist petroleum engineer this variety can confuse and distract from effective use of the measurements. We organize all categories of pulsed neutron logs into simple types based upon the measurement physics to provide an effective guide to field use of these logs.
Examples of commercial and experimental tools in clastic and carbonate environments are presented. The examples show how CO2 can be quantified and demonstrate critical design requirements for successful pulsed neutron logging campaigns. We outline the lessons learned and make recommendations for the design of logging programs and interpretation of the acquired data in stand-alone or in time-lapse modes.
Tsar, Mitchel (Curtin University) | Bahrami, Hassan (Curtin University) | Rezaee, Reza (Curtin University) | Murickan, Geeno (Curtin University) | Mehmood, Sultan (Curtin University) | Ghasemi, Mohsen (Curtin University) | Ameri, Abolfazl | Mehdizadeh, Mahna
Tight gas reservoirs are mainly characterized by low matrix permeability and significant damage. During drilling and fracturing of tight formations, wellbore liquid invades into tight formation and increases water saturation around wellbore and eventually reduces permeability near wellbore or adjacent to fracture wings. The damage to permeability caused by invasion of liquid into tight formation is controlled by capillary pressure and relative permeability curves.
The phase trap damage is one of the main concerns in use of water based drilling or fracturing fluid, since due to high critical water saturation, strong capillary pressure, and sensitivity of tight sand to water. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formation may result in a three-phase relative permeability curves in invaded zone in presence of reservoir gas and initial water, which may differently affect damage and productivity of tight gas reservoirs.
This study evaluates phase trap damage in water-based in comparison with oil-based drilled or fractured tight gas reservoir. Reservoir simulation is used to study the effect of relative permeability curves on phase trap damage and well productivity, based on reservoir and core data from a West Australian tight gas reservoir. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of improving well productivity.
The prediction of dynamic elastic constants of reservoir rocks is one of the most important aspects of petroleum engineering. In recent years, several studies have been performed for this purpose. Because of uncertainty and variability in natural materials, deterministic prediction of rock properties in the reservoir is not reasonable. The purpose of this study is to evaluate uncertainty in dynamic-elastic-constant prediction for reservoir rock. Dipole-shear-sonic-image (DSI) log data from one of the Saudi Arabian reservoirs are used to evaluate uncertainty in dynamic-elastic-property prediction. For this purpose, a multiple linear regression (MLR) is carried out to present an empirical equation for shear-wave (S-wave) velocity prediction. Then, probabilistic analysis using Monte Carlo simulation (MCS) is performed to evaluate the uncertainty and reliability in prediction of dynamic elastic constants (Young's modulus and Poisson's ratio). On the basis of the analysis, uncertainty and variability of rock elastic constants are considered, and the value of Young's modulus and Poisson's ratio in a special interval from the reservoir are determined with a certain probability. Finally, the impact of log-data parameters on the value of rock elastic constants in the reservoir interval is assessed.