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.
The objective of this paper is focused on presenting and highlighting the results of the first successful reservoir fluid characterization and sampling attempt in offshore Abu Dhabi and the added values to the assets operating in the highly heterogeneous Jurassic carbonate reservoirs with unknown formation water salinity values. The original formation water has a unique high salinity that got mixed overtime with the fresher injection water, so that the open hole log interpretation using Archie water saturation model becomes highly uncertain. Exaggerated oil saturations could be computed within the water zones around the oil-water contact. In addition to measuring the fluid mobility, the formation testers are being run to confirm the fluid type present in the reservoir by using pressure gradient plot or by fluid identification and sampling stations. The increasing cost and rig time optimization demands inspired the team to utilize the emerging formation sampling and testing while drilling at the first time in offshore Abu Dhabi to replace the conventional wireline/ drill pipe conveyed formation testers. This application proved to be an added value to gather the required reservoir data in a mature challenging field reducing the operational time, cost and associated risks. A water injection well is drilled across a highly heterogeneous, Jurassic carbonate reservoir offshore Abu Dhabi. A deviated pilot hole was drilled for formation evaluation and reservoir fluid assessment, and the plan was to continue with a horizontal drain into one of the sub-reservoirs (swept area) if confirmed water bearing. The logging while drilling formation sampling and pressure testing tool was run combined with the conventional open hole logs to minimize the formation exposure time, real time down-hole fluid analysis started very shortly after drilling to the bottom of the target reservoir, based on the rush open hole log interpretation. Different sensors, with different physics (namely; fluid viscosity, density, sound speed, optical refractive index, temperature, fluid mobility and compressibility) were used to characterize the fluid during the pump-out stations. Due to the minimized mud filtrate invasion effects, this operational sequence allowed the gathering of conclusive formation fluid samples with less pumping time and volume. This paper shows the operational planning, design and execution outlines, discusses the benefits of acquiring clean formation samples right after drilling compared to those acquired with the conventional conveyance techniques, and indicates the drawbacks and the limitations of this technology together with any window of improvement.
The lower cretaceous carbonate sequence, offshore Abu Dhabi is represented by the third to forth order sequences. Limestone is the dominant lithology for this group of ramp to intrashelf basin sediments. Fracture intensity and density vary vertically along the sequences, controlled by rock texture contrast. Dense layers are heavily fractured compared to the porous bodies throughout these Formations. Two dominant sets of fractures are observed throughout the field, NW-SE and NNE-SSW. Historical well test data indicate strong preferential flow in that same direction compared to less flow in the NW-SE trend (anisotropic drainage behavior). The objective of this study is to demonstrate the capabilities of simultaneously acquired near and far field borehole sonic reflection logging measurements to characterize the present fractures along a dedicated horizontal drain for data gathering. Borehole image log interpretation and other well logs are integrated. Understanding fracture systems using resistivity imaging solely could be challenging due to the limited depth of investigation of the measurement (at the well location). Well trajectory, (open) fracture density and orientation can cause uncertainties in the number of fractures that intersect the borehole. Primary fractures could be abundant away from the borehole but still contributing to flow and reservoir pressure behavior. With a unique extended depth of investigation as well as azimuthal sensitivity, dipole sonic imaging is able to reach tens of meters into the formation and provide fracture intensity and extension information in the far field. A new scale of data integration using near field measurements from monopole sonic imaging, Stoneley wave reflectivity analysis and borehole image interpretation for a comprehensive fractures characterization is accomplished. A set of structural incidents could be detected tens of feet away from the borehole, some seemed to be extending towards the borehole wall itself as seen by the Stoneley reflectivity and the sonic-resistivity borehole imagers. Open fractures are clearly characterized in terms of orientation and aperture, extension inside the reservoir could be recognized, small-scale fractures near the borehole could be discriminated, as well as the closed ones, in addition to the dense stylolite markers. Comparisons with offset cores, seismic and offset well data shows a range of coherence. Most of the fracture clusters were observed at the stylolite boundaries. The main orientation of these fractures are consistent with the present day in-situ stress orientation. The integration of data with respect to resistivity, sonic borehole image and Stoneley wave data from sonic monopole processing are in coherence. Far-field dipole shear sonic imaging adds valuable information to investigate the major carbonate reservoir structural incidents away from the borehole. The value is maximized by integration with the high-resolution borehole image that drew some conclusions on the presence of different sets of fractures distribution and their nature.
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.
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