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 oil rim with a large gas cap reservoir 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. The reservoir rock properties showed 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 producing the oil rim while maintaining the gas cap as long as possible to save the reservoir energy and benefit from the gas cap pressure support. Five years production dynamic data were available from two oil producers in addition to well testing and MDT data during the appraisal phase "13 wells". These data were used to quality control the initialization and history match phases. The development options included pressure support using water injection, lean gas injection, miscible gas injection and miscible WAG injection. The predicted reservoir performance of the oil rim indicated considerable gas cusping from the gas cap in all the development options. It was a challenge to reduce the amount of gas production from the gas cap in all the development options. A new development option was introduced to perform miscible gas / WAG injection underneath the gas cap accompanied with optimization of the wells and completion intervals locations for producers and injectors to minimize the gas cusping from the gas cap. This resulted in significant enhancement of minimizing gas cusping with minor impact of the recovery factor. The development of the oil rim was suggested to be in phases focusing on the lowest uncertainty segment of the reservoir. This paper provides the methodology followed to guide the development plan to fill in the uncertainty gap by a detailed data acquisition and monitoring programs to better understand the reservoir behavior.
This work illustrates field development plan and optimization studies conducted on a Middle-Eastern carbonate reservoir. The field lies in an onshore area where increasing urbanization is complicating the field development with regard to safety, accessibility, and drilling sites. The reservoir exhibits relatively fair to poor reservoir characteristics and variable oil water contacts due to faulting, suggesting the presence of 5 different reservoir compartments. A total of 10 wells had penetrated the reservoir out of which 8 wells tested oil and suggested a huge initial gas cap while 2 others penetrated water leg. Six years of early production scheme (EPS, 4 producers, 1993 to 1998) data in addition to production testing, core (2 wells), MDT (3 wells), PVT (4 wells) data were gathered in order to identify the main uncertainties and test the feasibility of the full field development. EPS indicated production decline coupled with severe increase in GOR and water cut in some wells, after which the producing wells and facilities were P&A due to safety concerns and low productivity. A number of parameters were addressed and optimized during the full field development plan. These include formation evaluation and modeling parameters based on EPS findings, the limited available data, and pressure support mechanism. Several development scenarios were constructed, consisting of various combinations of horizontal producers and injectors and considering natural depletion, WI, GI, and WAG scenarios targeting the proven reserves. The dynamic modeling suggests that an ultimate recovery of 70% can be achieved by the different injection scenarios. However, considering the complexity of the surrounding environment and the size of the prize, it is recommended that the field development would be economically viable for a period of 10 years under natural depletion, provided the most effective development strategy in terms of number, location, orientation and horizontal reach is adopted.
This paper presents a case study of developing a complex super k thin carbonate reservoir with a thin upper super permeable layer with a significant volume of oil, a gas cap and an active water drive in Abu Dhabi-UAE. The field lies in a coastal marine area covering mainland, natural and artificial islands as well as shallow and deep marine areas. The reservoir lies within a relatively low relief heterogeneous carbonate structural trap originally deposited within a complex depositional environment, characterized by lateral and vertical variations in reservoir rock and fluid properties. Six years of production dynamic data are available from oil producers in addition to well testing and MDT data. The production is constrained by the presence of a high permeable streak just below the dense carbonate top seal and bounded by gas cap above and water below. This streak dominates the drainage of reservoir in such a way that the majority of the wells completed suffer from early apparent gas cusping and increasing water production. The reservoir has been penetrated by vertical, deviated and horizontal wellbores. In relation to this, differences in production performance have been observed, specifically with respect to gas oil ratio and water cut. During the early development stage, three horizontal holes were drilled, however due to the difficulties of proper geo-steering of the horizontal hole placement within the thin oil column, two holes were placed in the gas cap and the third was placed in water. The main challenges of current and future development plans are the optimization of well design, placement and completion strategy to avoid the gas cap and transition zone. This paper discusses the lessons learned from the ongoing development of the mentioned reservoir and the way forward for the future development phases.
Recent appraisal campaign on a producing field in onshore Abu Dhabi has found evidence of oil presence 60-170 ft below hitherto known Free Water Level (FWL). The Oil water contact (OWC) was identified by electrical and mud logs, geochemistry analyses on core plugs and well cuttings, core stain, core UV, thin sections and Dean Stark saturation. The calculated volume of the hydrocarbon (HC) below the FWL is significant. However, below FWL, one well tested traces of oil. A comprehensive study including geochemistry was commissioned to understand hydrocarbon composition and its mobility for reserves evaluation and future development plan Total of 1600 ft of core was acquired from three appraisal wells and cuttings from two wells. Pyrolysis was conducted to evaluate hydrocarbon presence and its composition. Subsequently, a subset of sample from pyrolysis data was selected for solvent extraction and detailed analysis for oil characterization. Saturates, Aromatics, Resins and Asphaltene (SARA) fractions were measured on few samples. Finally, Gas Chromatography and Compound Specific Isotope Analysis (CSIA) were performed to compare the extract with the produced oil from the crestal area to assess the variation of HC composition Parameters derived from mud log have provided a good understanding of hydrocarbon distribution. Thin section and Scan Electron Microscope (SEM) observation showed presence of black, solid carbon particles (Solid bitumen) in the pore spaces despite solvent cleaning. Oil Saturation Index (OSI) and solvent extraction show lower and higher values below and above the OWC, respectively. S1 and S2 yields provided a detailed understanding of hydrocarbon distribution. Saturate composition was highest at reservoir top where the only MDT sample (22% of oil) was successfully collected, whereas it was low where only water on MDT and traces of oil (>99% BSW) were collected during testing. The pyrolysis data, typically applied to assess source rock quality and maturity, has been utilized successfully in a novel approach to assess the oil distribution and its composition in a conventional reservoir. It is now understood that, in addition to reservoir rock facies, oil facies should also be established to achieve a comprehensive reservoir assessment in this challenging reservoir that has witnessed multiple phases of hydrocarbon charge as indicated by solid bitumen and liquid hydrocarbon. These dispersed bitumen particles are likely to provide large adsorption surface areas for any oil that might otherwise would have been available for flow upon testing.
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