The tight sand oil reservoir found in the Ordos basin is known for its very low porosity and permeability. Almost every well has been stimulated using hydraulic fracturing techniques. The average production for a vertical well is approximately 4–5 tons per day. Among such a large number of fracture jobs, enhanced production after stimulation does not always meet expectations. Since2005, hydraulic fracturing monitoring services have been carried out widely in this field to improve fracture geometry understanding and optimize well placement. With the implementation on-site, real-time hydraulic fracture monitoring, the pumping procedure can be adjusted accordingly based on the mapped microseismic events. Based on the past hydraulic fracturing monitoring experience in this field, an average microseismic event detectable distance range around 300 m is expected for the case of geophones inside a monitor well. Two parallel horizontal wells were thus drilled at 600m apart. Horizontal section length is around 1,500m for both wells. The original hydraulic fracture plans for each well consisted of 18 stage stimulations, but were subsequently adjusted to 13stages based on real-time hydraulic fracture monitoring results. Three monitoring wells were drilled from toe to heel as shown in Figure 1. These monitor wells will also be used as water injection wells in later secondary recovery processes. So hydraulic fractures generated by the pumping from both horizontal wells are not expected to extend far enough to reach the monitor wells. With this favorable well layout, simultaneous dual-well hydraulic fracture monitoring was proposed and conducted. In order to obtain the optimized fracturing parameters first, the initial 3 stages of each treatment well was conducted at one stage per well i.e. stimulate well-1 and then move to fracwell-2. Simultaneous hydraulic fracturing began after the initial six stages were completed.
Clastic gas reservoirs can be made economical through effective stimulation techniques. Hydraulic fracture mapping based on seismic techniques can lead to better understanding of the effectiveness of reservoir stimulation, when combined with in-depth reservoir geology and geophysical knowledge make development of such fields feasible. Two stages, out of five hydraulic fractures stimulation were monitored and mapped in an attempt to assess the fracture propagation in a clastic gas reservoir located in Rajasthan, Western India. This was the first hydraulic fracture monitoring in India using downhole wireline sensors whereby recorded microseismic (MS) events indicating fracture growth as they are being created by rock failure. Events triggered by the stimulation treatment are detected and located in a four-dimensional (4D) space (space and time) relative to the well being treated. The microseismic images indicate that fractures are well distributed within the Upper and Lower Fatehgarh formations, in the north-east south-west azimuth. The first monitoring was done on Stage-4 and recorded very few MS events, but indicated a relatively contained fracture. The fracture geometry estimated from the mapping matches closely with the parameters anticipated from the frac modeling work. The second monitoring was done on shallower Stage-5 and showed downward height growth during the initial stage of the treatment. This observation indicates that the hydraulic fractures may have intercepted a fault located within the treatment well. The result is being integrated with the planned stimulation model, mini-frac data, stress profile and other geological information. This will help in calibration of the stimulation model. Understanding of the fracture geometry from this technique along with the fracture geometry available from fracture modeling, well testing, etc. shall be combined to arrive at optimized designs for future fracturing campaigns in this clastic gas reservoir.
Frontier drilling in deepwater environments is challenging with a wide range of risks that oil operators need to evaluate carefully because of high-investment costs. The formation targets selected are typically depth transformed using a velocity function obtained from conventional 3D surface seismic data. The data are usually low resolution and may not have been processed with the best prestack depth migration (PSDM) techniques. This pitfall often leads to uncertainties in reaching drilling targets and completing the well on time. Common uncertainties faced by drillers are target confirmation ahead of an intermediate depth section and the distance to these targets. One approach to reduce this uncertainty is to use borehole seismic techniques to record a vertical seismic profile (VSP) at intermediate total depth (TD) to look ahead and estimate the target depths below the bit.Oil and Natural Gas Corporation Limited (ONGC), India's largest oil operator, has been using this simple, effective technique in drilling deepwater wells. In one case the look-ahead prediction resulted in stopping of drilling operations because ONGC needed to ascertain if there was reservoir rock below the volcanics. The unambiguous VSP result did not show any possible reservoir below 3987 m measured depth (MD), which saved 3.5 weeks of drilling to reach the predrilling planned TD of 4415 m MD. In another example, ONGC needed to complete a vertical well that extended to basaltic basement with TD planned at 4324 m at a subsea water depth of 2135 m. Three look-ahead VSP runs were performed at various sections for guidance throughout the drilling process, setting the casing, and reaching the deeper final target. Final TD was 6205 m MD as opposed to the planned TD of 4324 m MD.While VSP techniques have been widely used by the exploration communities particularly the geologists and geophysicists, they are also a look-ahead tool applicable for drilling operations planning and ahead-of-bit drilling risk mitigation.
Seismic while drilling (SWD) technology was first time being used by Oil and Natural Gas Corporation, ONGC recently, on their Andaman Seas deepwater drilling campaign. Numerous publications have been made by the industry experts over the past 10 year on SWD technology In this case study we demonstrate the practical applications of SWD technology that help to guide the real-time drilling process with effective cost and time in acquiring checkshot data. ONGC has started exploration campaign in Andaman deep water area recently in 2011. The drilling was commenced with very limited information available from surface seismic, because of no well control in the area. By virtue of surface seismic technique, uncertainties are always associated with it. Uncertainties in seismic impacts the well plan and safety, which effectively impacts the well cost.Any technology which can reduce the seismic uncertainties and risks can be useful to reduce the cost and enhance safety. In this paper a case example is presented, where real time checkshot was acquired without disturbing the normal drilling operation .The real-time checkshot was recorded at every drill string stand and recorded waveform was transmitted uphole through mud telemetry system. The computed time-depth function was used to refine pre-drill velocity model and this was subsequently used to update the drilling target prognosis depths and geomechanics model. Real-time checkshot also confirmed the drill bit position on the surface seismic section. Updated seismic lookahead give confidence to ONGC to continue drill ahead with single 12.25" hole to reach their final TD at 3700m. All targets were reached within a few meters errors of the prediction. This case study demonstrated that SWD technique added considerable values in helping eliminating drilling 17.5" enlarge hole and 13 3/8" casing run.
TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractA unique integrated borehole seismic technique was used to access and mitigate drilling risk on a Petronas Carigali highpressure, high-temperature (HPHT) exploration well offshore Sabah.The approach combined wireline vertical seismic profiling (VSP) and logging-while-drilling (LWD) seismic surveys to look ahead for pore-pressure prediction, geostopping, and obtaining high-resolution seismic imaging below the well path. Three wireline VSP runs and one seismic-while-drilling run were made. The first-run rig-source VSP at the 13 3/8-in. section was used to obtain an initial velocity model and early prediction ahead of bit and imaging. This was followed by a wireline vertical incident VSP (VIVSP) run at the 9 5/8-in. section to refine the pore pressure prediction and for target illumination. LWD seismic was deployed while drilling the following 8 3/8-in. section to provide real-time checkshots for pore-pressure constraint and geostopping above a key formation top to set casing. Both the wireline and LWD VIVSP showed minor faults that were not apparent on the 3D surface seismic; these faults explain the unusual kick encountered. This high-resolution image was used to decide the sidetrack path. The final rig-source VSP was logged at total depth (TD) to complement the pore-pressure prediction and seismic imaging.In addition, the real-time checkshots while drilling aided in stopping drilling to within a stand (less than 30 m) above the key formation top. The depth uncertainty of the key formation was over 130 m prior to drilling.
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