Sourceless porosity estimation has become more attractive because of evolving government regulatory and HSE requirements. The use of wireline nuclear sensors and their HSE procedures have a 50-year history, while nuclear sensors for logging while drilling share the last 20 of those years. Recently, the potential of using non-nuclear methods for porosity estimation has been explored in an offshore Abu Dhabi carbonate sequence. This paper presents a case study of nuclear magnetic resonance (NMR) logs while drilling, in comparison to conventional density and neutron logs using radioactive chemical sources. NMR T1 porosities were also compared to laboratory core results. Two approaches are investigated: Estimated hydrogen-index correction to NMR moveable-fluid volume using core-normalized porosities.An insight into an integrated NMR-acoustic approach, using the two sensor measurements to derive a corrected porosity. A workflow is proposed for optimized job planning, operational procedures, data-acquisition parameters, and interpretation techniques. Permeability estimation with NMR is discussed, and a selection of methods are considered and contrasted to laboratory core permeability and wireline formation-tester results. This paper explores the potential for sourceless porosity measurements through NMR and acoustic/NMR measurements in an offshore Abu Dhabi carbonate sequence in compliance with the HSE standards and government regulations, where the need for reconsidering reservoir characterization through sourceless porosity options will continue to grow.

Sourceless well logging (logging without using traditional chemical sources) has become more attractive in certain locations because of evolving government regulatory and HSE requirements. LWD sonic tools provide opportunities to operators for both well placement and formation evaluation. For the first time in the UAE, an LWD acoustic tool was added to a bottomhole assembly (BHA) to acquire sourceless porosity measurements to help stay in the porous sub-layers in the target reservoir. In comparison to more traditional nuclear measurements, LWD sonic has a superior depth of investigation that is less affected by standoff and a driller-friendly BHA free from stabilizers. Based on the evaluation of offset data, which indicated excellent correlation of sonic vs. density/neutron measurements, we decided to provide shear porosity in real time owing to the sequence stratigraphy and corresponding energy partition. A post-job comparison with density/neutron data acquired in a wipe run was also conducted to verify the sensitivity of real-time acoustic porosity measurements for both well-placement and formation-evaluation purposes. Sonic-derived porosities were found to be instrumental in the real-time decision making needed to keep the well the in higher porous sub-layers. Current developments, including real-time azimuthal sonic together with considerations of integrating acoustic and NMR measurements in both petrophysical modeling and field applications, show promise in providing reliable sourceless porosity estimation in these formations. This case history delivered a BHA free from radioactive chemical sources. Safe drilling objectives as well as maximized productivity per unit lateral length were achieved despite the potential risks associated with the faults that were observed in the pilot hole. Introduction With a global focus on exploring oil and gas with minimum environmental impact, the regulations in the region are very strict on adhering to zero harm to the environment. One of the most stringent laws in place is with regards to the abandonment of radioactive sources in the well in the event of a stuck pipe. ADMA OPCO is an active player in helping service companies develop and improve on their “sourceless” alternative technologies to reduce potential risks associated with stuck pipe. Real-time acoustic measurements were used for well-placement purposes in Field A, which is one of the giant fields located in offshore Abu Dhabi. Oil was discovered in 1958, and production began in 1962. Down-flank water injection started in 1973 followed by crestal gas injection in 1994. The Arab reservoir in Field A was formed from regressive cycles of sedimentation divided into four highly heterogeneous sub-reservoirs (labelled in ascending order from A to D (Fig. 1)). The principal oil-producing reservoirs are Arab zone C and Arab zone D, whereas Arab zones A and B still remain undeveloped. Based on the core description, the Arab reservoir section is mainly composed of three lithologies, namely, anhydrite (purple shading), dolomite (green), and limestone (light blue), as shown below in Fig. 1.

Hydraulic fracturing is an important technique widely used for to improve well productivity in tight reservoirs and enable economic development. Geomechanical modeling is an important prerequisite required to ensure effective fracture construction and the required contact with the formation. In this paper, we show the first successful hydraulic fracturing in the Offshore Abu Dhabi clastic sand formations in which geomechanical modeling played an essential role in fracture design, completion design and successful execution.The geomechanical properties and behavior of the clastic sand formations are still largely unknown in the Abu Dhabi region. In other parts of the Arabian Plate this formation is known to be a complex geological environment with high fracture gradients, poorly consolidated intervals, natural fractures and often rock that exhibits poroelastic behavior.Due to the aforementioned complex geological environment resulting geomechanical attributes, the fracture design and key inputs including the calibrated Mechanical Earth Model (MEM) were essential to the successful design and execution of the first hydraulic fracturing in the Offshore Abu Dhabi clastic sand formations. The lessons learned during this successful design and application is critical for the design of future wells and the development of the UAE clastic sand formations.The constructed MEM played a key role in successful hydraulic fracturing. Fracture height, length, width, direction, complexity and overall fracture performance are all largely controlled by the formation stresses, stress direction, rock properties and complexity of the rock fabric.Geomechanical properties in the clastic sand formations in Abu Dhabi offshore were evaluated with less uncertainty by utilizing the advanced MEM. The calibrated MEM was integrated with an advanced fracture design simulator to optimize hydraulic fracture design. Results of the advanced MEM agreed well with fracture diagnostics and temperature surveys.Work flow in this geomechanical analysis can be applied to hydraulic fracturing in other offshore tight reservoirs with a complex geological environment. Understanding the geomechanical properties of a formation allows engineers to optimize well placement, completion design, perforation placement, charge/gun selection and fracture design for improved well productivity.

With the popularity of nonconductive drilling fluid (NCM), a new generation electrical borehole imaging tool that uses megahertz logging frequencies is developed to decrease the capacitance of the NCM for acquisition of high-resolution images. At this frequency range, both electrical conductivity and dielectric permittivity of the subsurface dictate the logging measurement. This challenges our understanding of the tool response in terms of resistivity contrast and affects the algorithms in the geologic interpretation software that use the resistivity image value. For example, open vugs filled with NCM can appear resistive on images and invalidate the basic assumptions of existing secondary porosity quantification software that open vugs are filled with conductive mud (since they were developed for water-based mud). A new laboratory device that features the same logging frequency, as the logging tool has been developed to assess the new algorithms for quantitative interpretation. The device was used to investigate images of secondary porosity features acquired in NCM in controlled laboratory conditions. It is demonstrated that for effective analysis of fluid-filled vugs, a resistivity image is not sufficient to count the NCM-filled vuggy area. A new post processing method is introduced by combining the effects of resistivity and dielectric permittivity and generating a new image called the rock Hayman factor image. On the Hayman factor image, it is possible to differentiate fluid-filled vugs from cemented vugs. Based on this analysis, a new NCM vuggy formation characterization workflow is proposed. The workflow was applied to a downhole case study for a vuggy carbonate reservoir. The Hayman factor image agrees with the resistivity log/image in identifying oil, transition, and water zones in the well, and it shows enhanced heterogeneous texture patterns in different zones. Software incorporating Otsu's method was capable of discriminating between the continuous rock background phase and heterogeneous phase by varying input parameters and was used to test the image feature contrast of a resistivity image logged in oil-base mud (OBM) by using the conventional heterogeneity analysis method and the new Hayman factor image. Interestingly, when the OBM-logged resistivity image is input, no vugs were found in the area where core photographs indicate vugs are present. However, running the software on the Hayman factor image can characterize vugs with a frequency that matches well with the core photographs. This shows that the Hayman factor image has improved feature contrast compared with the original resistivity image. The new postprocessing Hayman factor image is designed to quantify rock resistivity and the dielectric permittivity effect. A new vug characterization workflow using this new image is proposed for NCM environment secondary porosity quantification.

TX 75083-3836, U.S.A., fax ϩ1-972-952-9435understand not only the geological characteristics, but also the variations in reservoir properties within seemingly similar facies.This work presents the first account of interpretation based on a new technology for OBM formation imaging, with innovative inversion techniques. This also serves as a roadmap for carbonate reservoir characterization in Middle East in the wells drilled with OBM. Also, the encouraging results provide a trendsetting example of applications of this new technology.