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Franquet, Javier (Baker Hughes, a GE company) | Shaver, Michael (ADNOC Offshore) | Edwards, Ewart (ADNOC Offshore) | Neyadi, Abdulla Al (ADNOC Offshore) | Noufal, Abdelwahab (ADNOC Upstream) | Khairy, Hamad (Baker Hughes, a GE company)
Abstract A pilot was drilled offshore Abu Dhabi aiming to determine the in-situ stress magnitudes. A time-dependent reactive shale formation separates Middle and Lower Cretaceous Limestone formations, leading to difficult open-hole logging conditions. Determining the stress regime and stress contrast across these formations is critical for assessing wellbore stability in extended-reach wells, setting casing shoe depths, and designing hydraulic fracturing in the tight reservoirs. Therefore, a comprehensive logging including multiple in-situ stress measurements and full-core was acquired. Seven microfrac stress measurements were obtained in one pipe-conveyed straddle-packer run conducted in a 15°-degree deviated 8½-in. open-hole wellbore. Each microfrac test was designed with multiple pressurization cycles to accurately obtain the closure stress away from the near-wellbore zone. Core and logging data from offset wells were used to calibrate the pre-job microfrac assessment. Real-time data monitoring was implemented for quality-control and tool operation decisions while logging. Three different pressure-decline analysis methods were used to identify the fracture closure: (i) SQRT square-root of time, (ii) G-function, and (iii) Log-Log plot on each microfrac station. The pilot well required an inhibited oil-based mud system to stabilize the 360-ft. water-sensitive shale formation. All microfrac stress measurements successfully reached the formation breakdown pressure, providing clear propagation and fracture closure identification. The three pressure decline methods produced results around ± 15 psi from each other with G-function predominately higher and Log-Log predominately lower than the SQRT. These microfrac tests measured minimum horizontal stress gradients between 0.67 to 0.77 psi/ft confirming the normal faulting stress regime in the studied reservoirs and a near strike-slip stress regime in the intervening shale formations. The formation breakdown, fracture reopening and closure pressure provide an accurate present-day tectonic model with ~0.1 and ~0.9 mStrain in the minimum (N80°W) and maximum (N10°E) horizontal stress directions in the absence of breakouts and induced fractures on image logs. The Lower Cretaceous tight reservoirs, identified as generally thin (<10-30ft) and low-quality (<10mD, locally <1mD) microporous carbonates, were located between low stress contrast (0.69 psi/ft) clay-rich limestones intervals in the overburden and high stress contrast (0.74 psi/ft) denser dolomites and clean tight limestones in the underburden. The risk of tool plugging and unsuccessful latching due to large particle solids in the mud was mitigated by multiple mud filters and repeated circulations while running-in hole with the straddle packer module. The microfrac tests in the Lower Cretaceous tight reservoirs provide the stress contrast measurements to properly evaluate hydraulic fracture containment on these tight reservoirs for future field development plans.
The objective of this work is to highlight wireline straddle-packer microfrac testing is an underutilized technology today by the oil and gas industry despite these tests have evolved significantly in the last 10 years. This work also summaries the technological improvements and latest advances of microfrac service deployment in addition to share the future of in-situ reservoir stress monitoring from fiber-optic Distributive Strain Sensing (DSS).
Over 500 microfrac tests and more than 30 decades of stress testing data are compiled and analyzed from science and data-collection pilot wells drilled around the world. The number of pressure tests collected by the industry is estimated by Baker Hughes’ database and competitor’s market share to compare the substantial difference between the number of reservoir pressure points and microfrac stress test collected every year for the last decade. Machine learning algorithms predict tectonic strain values to match microfrac formation breakdown and fracture closure using basic rock elastic properties to calculate the static stiffness of the formations where the stress tests are obtained.
The microfrac success rate has increased from 20% to 85% in the last decade thanks to upgraded straddle packer tool capabilities and improved operational practices. The formation breakdown pressure data consistently indicates higher level of uncertainty than reservoir pore pressure. However, the industry collects several orders of magnitude more pore pressure points than microfrac stress tests every year. Possibly, this is the consequence of using basic effective in-situ stress ratio models by geomechanics practitioners that requires few calibration points from leak-off tests or borehole breakout modelling. This practice could treat microfracs as a nice-to-have calibration data rather than an essential subsurface tectonic stress information. A significant increase in microfrac testing is observed during the US shale gas revolution in order to calibrate stress profile models where basic effective stress ratio models failed to predict a lithology-dependent stress contrast between pay and non-pay intervals. The data shows the importance of using microfrac tests to calibrate subsurface tectonic strain values and predict accurate hydraulic fracture containment.
The predicted tectonic strain data from microfrac testing shows values between 0.05 to 1.2 mStrain which can also be detected with current fiber optic technology using two centimeter grading and capable of detecting two micrometers of deformation. This new distributed strain sensing technology can be implemented to detect changes of stress and strain as the reservoir is developed by producer and injector wells. This technology may be the future of stress monitoring at the reservoir scale.
Wang, Chenglong (Baker Hughes Company) | Xiao, Chengwen (Tarim Oilfield Company, Petrochina) | Xin, Yi (Tarim Oilfield Company, Petrochina) | Duan, Wenxing (Tarim Oilfield Company, Petrochina) | Zhang, Chengsen (Tarim Oilfield Company, Petrochina) | Zeng, Xianlei (Baker Hughes Company) | Han, Dongchun (China Oilfield Services Company)
The development of a vuggy carbonate reservoir is very challenging because of low porosity and permeability in the matrix. Natural fractures and caves play a dominate role in this kind of reservoir. Production of these reservoirs highly depend on whither fracture-cave cubes are successfully targeted. Consequently, it is very important to determine the entire picture of the natural fracture-cave systems near to and away from the borehole.
The traditional ways to evaluate fractures or caves in acoustic logging are Stoneley permeability, azimuthal shear-wave anisotropy analysis, along with resistivity image logging. However, the depth of investigation of all these methods is limited from less than one inch to a few feet from the borehole wall. Deep shear wave imaging is a new way to image the reflectors offside the borehole. This imaging technique uses the shear body wave that is reflected back to the borehole by the acoustic impendence differences caused by planar features (such as fractures and caves) in the formation. After suppression of the direct wave mode and migration of the reflected wave, it gives a picture of the fracture system around the borehole. In addition, it has a much deeper depth of investigation, which depends on the shear slowness and attenuation of the formation. Normally, in carbonate formations with shear slowness at 80 ft/us, deep shear wave imaging manages to see reflectors as far as 100 ft from the borehole. Compared to methods using monopole wave to imaging reflectors, deep shear-wave imaging has another important feature. Because it is using cross-dipole waveforms, which is azimuthally sensitive, therefore, the deep shear wave imaging can provide the azimuthal of the fractures—usually very important information for penetration and stimulation of the formation, also the possible locations of the reflectors are defined to help making sidetrack drilling decisions.
This paper describes a case study of deep shear-wave imaging application in a vuggy carbonate reservoir in Tarim basin. Conventional pertrophsical interpretation does not show good signatures in the borehole. Deep shear-wave imaging analysis shows two major reflectors away from the borehole. Combining seismic attributes and inversion analysis, the caves offside the borehole are located, helping the operator to make sidetrack decision. The sidetrack is successfully drilled into the cave. The value of deep shear-wave imaging is to provide a further insight of the natural fracture and cave system around the borehole, which cannot be achieved by conventional petrophysical methods.
Abdelkarim, Islam (ADNOC Offshore) | Jadallah, Haitham (ADNOC Offshore) | Ness, Knut (ADNOC Offshore) | AL ALI, Salim (ADNOC Offshore) | Alzaabi, Mohamed (ADNOC Offshore) | Amer, Reem (BHGE) | Diaz, Nerwing (BHGE) | Gjertsen, Morten (BHGE)
Abstract After completing the drilling phase of the 8½″ section for a well in a giant mature field offshore Abu Dhabi, due to geomechanical challenges it was not possible to run the 7″ liner in a shale formation which was open for a long period of time due to rig repairs (top drive failure in open hole), exposing all reservoirs and compromising the field development strategy. After several unsuccessful attempts to run the liner and leaving a drilling BHA in the hole during one of the cleanout runs, it was decided to sidetrack around the fish to intersect the original 8½″ open hole section in order to recover the original hole and isolate the reservoir flow units from each other, which was critical for the field development since more than five reservoir layers were opened with water and oil bearings increasing the risk of damaging the reservoir integrity due to potential cross flow. Detailed measurement-while-drilling (MWD) survey analysis was conducted for the original hole in order to enhance surveys accuracy and minimize positional uncertainty. Typical survey management practices were implemented for Sag and Drilling String Interference; other techniques such as Dual Inclination, In-Field Referencing, and Multi Station Analysis were also applied. The implementation of these different survey management practices and their respective results are covered in detailed in the current article. Comprehensive planning was carried out, the sidetrack was accomplished and the original hole was successfully intersected at the first attempt. The advanced applied survey management techniques were crucial, particularly in the absence of magnetic ranging as the interval to intersect was open hole. The outcome of these corrections resulted in a shift of 8ft to the final well position, ensuring the correct direction and position for a successful attempt to intersect the well. This intersection was particularly challenging as the original hole had a 3D profile, thus it was critical to minimize both vertical and azimuthal uncertainties. Intersection was achieved with an RSS BHA, and the success of this intersection without magnetic ranging capability was only based on following a planned well trajectory that intersected the original hole surveys, clear validation of the accuracy of the surveys for both original and sidetrack holes. Achieving this challenging directional drilling goal allowed the completion of the well as per original plan, which was critical for the field development plan of these reservoirs. Based on the fact that there is very limited existing literature covering similar cases to the one presented, this current case represents a solid successful reference to be replicated in similar cases in the future covering these challenging applications of advanced survey management techniques.
Karpekin, Yevgeniy (Schlumberger Logelco Inc) | Orlova, Svetlana (Schlumberger Logelco Inc) | Tukhtaev, Rustam (Schlumberger Logelco Inc) | Ovchinnikov, Alexey (Gazprom Neft Shelf) | Kuntsevich, Vitaly (Gazprom Neft NTC)
Abstract The article discusses the method of borehole acoustics reflection survey for detecting the presence and reconstructing the position of various reflecting surfaces, such as of large fractures, faults, bed-boundaries, in the near-well space at a distance up to 30m or more. The measurement principles, data processing, visualization and interpretation workflow developed by us based on the best published practices and supplemented by our solutions that significantly improve the quality and usability of the images are explained. A study of fractured zones identification and characterization in three horizontal wells based on the electrical microimager and the reflected acoustic survey is presented. Possibility of imaging the bed-boundaries of the host layers above and below the wellbore and specifying their position relative to the well's trajectory is demonstrated. Confinement of rocks with different reservoir quality within certain sub-layers of the target productive strata, identified with acoustic reflected survey, brings possibility to populate these properties more accurately in a refined structural model.