The reservoir in discussion is a tight carbonate reservoir with low productivity and relatively under-developed albeit the huge in-place volumes. The expectation is that a detail reservoir characterization will provide insight on factors affecting reservoir productivity, spatial distribution of productive portion of the reservoir and offering solution to overcome reservoir tightness. The case study discusses on how a comprehensive multi-discipline review unravels and presents a robust reservoir heterogeneity framework. A geological review that includes both depositional and diagenetic process is performed to understand distinct components/factors responsible for reservoir heterogeneity. Simultaneously, petrophysical assessment was performed to quantitatively define rock grouping based on porosity-permeability, capillary pressure and pore throat distribution in the log and core domain. The multi-discipline observations were then reconciled to establish relationship between the process origin and the resultant product of specific group/range of reservoir petrophysical properties. The multitude of pore throat characters and its petrophysical properties were linked to the underlying geological processes. The established heterogeneity framework provides clarity on spatial distribution of the reservoir sweet-spot, factors controlling low productivity and the required mitigation. The study provides a complete journey of unlocking tight reservoir potential. It illustrates the geological studies influence toward innovative completion technology selection, design, and execution to overcome reservoir challenge. The study is supported by recent drilling and test results, hence offering insight for adoption and lesson learned.
The Archie equation is the most common approach for calculating water saturation. The true formation resistivity that is derived from resistivity logs is an important component. In high-angle or horizontal wells (Ha/Hz) the commonly employed induction style tools and multi-propagation resistivity (MPR) tools employed in logging-while-drilling (LWD) have challenges. In particular, at bed boundaries, the formation-to-wellbore geometry affects deep-reading logs and generates artifacts such as so-called polarization horns on the logs. These effects become more significant with increases in the relative dip and the resistivity contrast between the beds. These conditions impair the use of resistivity for water saturation determination. An innovative modeling workflow to generate a true formation resistivity (Rt) from LWD MPR logs is presented. In addition, a number of case examples from Abu Dhabi reservoirs are portrayed. The workflow described in this study begins with the interpretation of borehole image data to build a structural earth model. For this, the picked boundaries are extended away from the trajectory within an investigative volume of the MPR responses and are used to constrain an inversion algorithm that solves for Rt. The inversion is conducted using eight short- and long-spaced apparent phase differences and attenuation data. Different starting models and inversion constraints are applied to evaluate the sensitivity of the inversion results. The inversion results are further qualified from the ‘misfit’ calculated by the inversion algorithm. This methodology was used to process data from multiple wells in a development field near Abu Dhabi. These high-angle wells are from carbonate reservoirs with varying characteristics (such as tight, layered, high-permeability streaks, etc) and all employ LWD measurements. The integrated data of vertical wells formation evaluation, dean stark and dynamic data (well test) were used to validate results of the case study. The processing results showed significant improvement in determining true resistivity that provided highly coherent saturation determination along the entire wellbore profile. It gave confidence in the effectiveness of the approach for an improved quantitative petrophysical evaluation in Ha/Hz wells. This new processing method is able to solve the existing issue associated with LWD measurement in high angle wells thereby improving the saturation calculation significantly.
This paper presents a case study of developing a significant volume of super K compartmentalized oil reservoir with a large gas cap and bottom water aquifer in Abu Dhabi-UAE. The reservoir is a low relief heterogeneous carbonate, located in a complex environment represented by natural and artificial islands in the surface, shallow and medium water marine areas with subsurface lateral, and vertical heterogeneities as well as variation in reservoir fluid properties.The static and dynamic data were utilized to construct representative geological and dynamic models for the reservoir. The field development objective focused on maximizing the oil production and achieving 70% RF while minimizing the gas cusping, water conning and early breakthrough via super K interval.Nine years production dynamic data were available from 6 oil producers in addition to well testing Љ14 wellsЉ, core Љ11 wellsЉ, MDT Љ17 wellsЉ data during the appraisal phase. These data were used to quality control the initialization and history match phases. In preparation to the development options, the team included pressure support using water injection, lean gas injection, miscible gas injection, miscible WAG injection. The predicted reservoir performance of the super K oil reservoir indicated considerable gas production and high water production from the bottom water aquifer through super K interval in all the development options.It was a big challenge to reduce the amount of gas production, water production, and early breakthrough for all development options. A new development option was introduced to perform peripheral miscible Hydrocarbon WAG injection accompanied with optimization of the wells and completion intervals locations for producers and injectors, as wells as WAG cycle to minimize the gas production from the gas cap, water production from the aquifer, and early breakthrough. This resulted in significant enhancement to plateau length, sweep efficiency, and recovery factor. This paper provides the methodology followed to guide the development plan to fill in the uncertainty gap along with a detailed data acquisition and monitoring programs to better understand the reservoir behavior.
Carbonate reservoirs from the Lower Cretaceous Thamama Group are of major economic interest since they host some of the largest hydrocarbon accumulations in the United Arab Emirates. This study focuses on a Thamama reservoir from the Kharaib Formation and aims at complementing the regional geological understanding through the integration of newly cored and historical wells. The reservoir of interest consists of a thick organic and clay-rich dense zone at its base characterised by mud-supported, discoidal orbitolinid-rich deposits. This interpreted mid-ramp dense succession is overlain by a thick reservoir unit deposited under inner ramp environments, hence describing a large-scale shoaling trend. In detail, the reservoir succession records higher hydrodynamic conditions than the dense unit, as testified by the predominance of grain-supported textures (from packstone to grainstone). Floatstone to rudstone interbeds with grainy matrices are associated with Lithocodium/Bacinella- and rudist-rich accumulations mainly recorded in the lower and upper parts of the reservoir, respectively. A series of depositional cycles of regional significance have been recognised throughout the reservoir succession and are usually bounded by prominent stylolites, correlatable across the field. The reservoir succession is predominantly characterised by micropores, although macropores (especially vugs) also have an important contribution to the pore system. The extent and impact of dissolution is highly variable, but overall, it is responsible for the creation of most macropores (ie. secondary macropores are more abundant than primary macropores). Subsequent to dissolution, the pore system is typically heavily degraded by cementation from non-ferroan calcite cements and, to a lesser extent, by dolomite cements. An emphasis has also been put on recognising the residual hydrocarbon, the abundance of which varies considerably at field scale. To better constrain the vertical and lateral distribution of the reservoir heterogeneities, nineteen layers of interest depicting the main reservoir quality trends have been interpreted. The creation of comprehensive sets of maps – consisting of sedimentological, thickness, diagenetic and hydrocarbon staining maps – for each of these layers allowed a high-resolution understanding of the reservoir architecture. Of interest is the upward increase in reservoir quality reported towards the upper part of the reservoir unit, associated with the development of thick rudist-rich intervals, which favour the development of a macropore-dominated pore system facilitating fluid flow. By contrast, the common presence of stylolites plays a key role in the creation of baffles or barriers throughout the entire reservoir. This integrated approach has allowed a better prediction of flow units at field scale and provided valuable input data for future reservoir modelling.
This work presents a case study of developing the transition zone for a giant oil reservoir with significant gas cap and water aquifer, in Abu Dhabi-UAE, addressing geological and dynamic aspects, field development approach and present status. The reservoir lies within a relatively low relief heterogeneous carbonate structural trap and characterized by lateral and vertical variations in reservoir rock and fluid properties. Given the relatively low permeability of the mentioned reservoir, the transition zone contains a significant STOIIP; which called for this challenging development. A number of parameters were addressed and optimized as part of the transition zone development plan. The dynamic modeling suggests that a full field ultimate recovery of 70% can be achieved by developing the transition zone. However, considering the complexity of the reservoir, thickness of the transition zone and current market conditions, the field development would be economically viable for a period of 50 years under miscible hydrocarbon WAG, provided the most effective development strategy in terms of the definition of transition zone, optimization of the number, location, orientation and horizontal reach of the proposed wells. Various development strategies for the transition zone were investigated during the study considering all possible uncertainties and economic drivers, all of which are discussed in details in this paper. 12 years of early production scheme (EPS, 1993 to 2005) and 12 years of phase-I development helped better understand the reservoir and characterize the transition zone. Total of +150 wells penetrated the reservoir with good data gathering (ROS, Core, SCAL, PVT, MDTs…etc.). PVT studies indicate a wide range of compositional variation areal and vertical, which further complicates the development plan considering the surrounding sensitive environment. The transition zone is defined by rock types and the corresponding critical saturation. The amount of recoverable oil in the transition zone is depending on the distribution of oil saturation as a function of depth and the relationship between initial and residual oil saturation in the transition zone. The reservoir is under EOR (Miscible HC GI at crest and WAG at flank) since commissioning of phase-I in 2005 and tracers were injected in 2012; adding challenges to the history matching and tracking of the flood front. Given the limitation on surface handling capacity of the current facilities, the transition zone development called for well placement in the upper part of the transition zone using 6 months WAG cycles. The first well of the transition zone development has been drilled; which has positively validated the definition of the transition zone, built confidence on the subsurface modeling approach and commended the planning strategy.
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