Bennett, Nicholas (Schlumberger-Doll Research) | Donald, Adam (Schlumberger) | Ghadiry, Sherif (Schlumberger) | Nassar, Mohamed (Schlumberger) | Kumar, Rajeev (Schlumberger Middle East S.A.) | Biswas, Reetam (The University of Texas)
A new sonic-imaging technique uses azimuthal receivers to determine individual reflector locations and attributes, such as the dip and azimuth of formation layer boundaries, fractures, and faults. From the filtered waveform measurements, an automated time pick and event-localization procedure is used to collect possible reflected arrival events. An automated ray-tracing and 3D slowness time coherence (STC) procedure is used to determine the raypath type of the arrival event and the reflector azimuth. The angle of incidence of the reflected arrival is related to the relative dip, and the moveout in 3D across the individual sensors is related to the azimuthal orientation of the reflector. This information is then used to produce a 3D structural map of the reflector, which can be readily used for further geomodeling.
This new technique addresses several shortcomings in the current state-of-the-art sonic-imaging services within the industry. Similar to seismic processing, the current sonic-imaging workflow consists of iteratively testing migration parameters to obtain a 2D image representing a plane in line with the desired receiver array. The image is then interpreted for features, which is often subjective in nature and does not directly provide quantitative results for the discrete reflections. The technique presented here, besides providing appropriate parameter values for the migration workflow, further complements the migration image by providing dip and azimuth for each event that can be used in further downstream boundary or discontinuity characterization.
A field example from the Middle East is presented in which a carbonate reservoir was examined using this technique and subsequently integrated with wellbore images to provide insight to the structural geological setting, which was lacking seismic data due to surface constraints. Structural dips were picked in the lower zone of the main hole and used to update the orientation of stratigraphic formation tops along the well trajectory. 3D surfaces were then created and projected from the main hole to the sidetrack to check for structural conformity. One of the projected surfaces from the main hole matched the expected depth of the formation top in the sidetrack but two were offset due to the possible presence of a fault. This was confirmed by parallel evaluation of the azimuthal sonic-imaging data acquired in the main hole that showed an abrupt change in the relative dip of reflectors above and below the possible fault plane using the 3D STC and ray tracing. Dip patterns from both wells showed a drag effect around the offset formation tops, further confirming the presence of a fault. A comparison of the acquired borehole images pinpointed the depth and orientation of the fault cutting both wells to explain the depth offset of the projected 3D formation top surfaces.
Kumar, Rajeev (Schlumberger) | Zacharia, Joseph (Schlumberger) | Guo Yu, Dai (Schlumberger) | Singh, Amit Kumar (Schlumberger) | Talreja, Rahul (Schlumberger) | Bandyopadhyay, Atanu (Schlumberger) | Subbiah, Surej Kumar (Schlumberger)
The unconventional reservoirs have emerged as major hydrocarbon prospects and optimum yield from these reservoirs is dependent on two key aspects, viz. well design and hydrofracturing wherein rock mechanics inputs play key role. The Sonic Measurements at borehole condition are used to compute the rock mechanical properties like Stress profile, Young's Modulus and Poisson's Ratio. Often, these are influenced by the anisotropy of layers and variations in well deviation for same formations. In one of the fields under review, the sonic compressional slowness varied from 8us/ft. to 20us/ft. at the target depth in shale layer in different wells drilled with varying deviation through same formations. This affected the values of stress profile, Young's Modulus and Poisson's Ratio resulting in inaccurate hydro-fracture design. At higher well deviation, breakouts were frequently observed and could not be explained on the basis of compressional slowness as it suggested faster and more competent formation. Current paper showcases case studies where hole condition improved in new wells with better hydro fracturing jobs considering effect of anisotropy in Geomechanics workflow. Sonic logs in deviated wells across shale layer were verticalized using estimated Thomson parameters considering different well path through same layer and core test results. Vertical and horizontal Young's Modulus and Poisson's Ratio were estimated for shale layers with better accuracy. The horizontal tectonic strain was constrained using radial profiles of the three shear moduli obtained from the Stoneley and cross-dipole sonic logs at depth intervals where stress induced anisotropy can be observed in permeable sandstone layer. A rock mechanics model was prepared by history matching borehole failures, drilling events and hydro-frac results in vertical and horizontal wells using updated rock properties. Geomechanical model with corrected sonic data helped to explain the breakouts in shale layer at 60deg-85deg well deviation where the original sonic basic data suggested faster and more competent formation with slight variation in stress profile among shale-sand layer. Considering shear failure, the mud weight to maintain good hole conditions at 80deg should be 0.6ppg-0.8ppg higher than that being used in offset vertical wells. Estimated closure pressure and breakdown pressure showed good match with frac results in deviated wells using new workflow. There was difference of .03psi/ft-0.07psi/ft. in shale layers using this new workflow which helped to explain frac height and containment during pressure history match. This paper elucidates the methodology that provides a reliable and accurate rock mechanics characterization to be used for well engineering applications. The study facilitates in safely and successfully drilling wells with lesser drilling issues and optimized frac stages.
Sonic imaging is a technique to obtain a high-resolution acoustic image of the earth formation structures several meters away from the well by utilizing the azimuthal sonic waveforms recorded for extended listening times downhole. The method has been used since the early 1990's to identify subseismic scale features (boundaries, faults, fractures, etc.) by migrating the sonic waveforms into a high- resolution 2D image.
Over the past two decades, the sonic imaging in the oil industry has been looked at as a ‘niche’ service. Limitations in acquisition telemetry to handle large datasets downhole and surface software processing capabilities as well as long job turnaround times have meant that sonic imaging service was primarily done on very few wells. Recently, sonic imaging has regained the interest of the community for input to structural modeling along with advancements of higher downhole data transmission capabilities and more powerful processing capabilities. The processing workflow itself, however, has mainly largely remained the same and has consisted of first filtering the sonic waveforms to reduce the interference of the borehole modes and then migrating the filtered waveforms to obtain a 2D image of a well section. Although the 2D image obtained from sonic data is of much higher resolution as compared to other available images such as surface seismic data and vertical seismic profiling (VSP), it does not provide quantitative information on the true dip and azimuth of the acoustic reflectors. With the advancements in the use of borehole resistivity images for geomodeling, the true dip and azimuth information is now essential for fracture characterization and structural geomodeling.
We introduce a new technique to obtain reflector location and associated attributes such as true dip and azimuth from fractures, faults, and layering from azimuthal sonic waveform measurements. The technique consists of two main steps. In the first step, an automated time pick and event localization procedures collect possible reflections from filtered waveforms; in the second step, an automatic ray tracing and 3D slowness time coherence (STC) procedure determines the ray path type and a 3D structural map of the reflector, as well as its true dip and azimuth. This technique also provides appropriate parameters for the orientation of the optimum 2D plane to migrate for the traditional image. The new technique enables determining the key parameters of true dip, azimuth, and reflector locations from higher-resolution sonic data required for reservoir evaluation and geomodeling. Direct integration with borehole resistivity images provides an opportunity to build a more accurate single-well structural model for identifying formation dip as well as a near-wellbore connectivity to far-field fractures.
This technique has been demonstrated using a case study, where sonic data were recorded in a horizontal well placed in unconventional Wolfcamp formation of North America. Characterization of natural fractures was critical for well completion and hydraulic fracturing. The 3D slowness time coherence (STC) results derived from multi-spaced and multi-azimuthal sonic data provided dip and azimuth of the fractures, which showed good agreement with image log interpretation. Image log results, which provides near-field information, were complimented with far-field 3D STC results.
Bennett, Nicholas (Schlumberger) | Donald, Adam (Schlumberger) | Ghadiry, Sherif (Schlumberger) | Nasser, Mohamed (Schlumberger) | Kumar, Rajeev (Schlumberger) | Biswas, Reetam (Schlumberger and University of Texas)
A new sonic imaging technique uses azimuthal receivers to determine individual reflector locations and attributes such as the dip and azimuth of formation layer boundaries, fractures, and faults. From the filtered waveform measurements, an automatic time pick and event localization procedure is used to collect possible reflected arrival events. An automatic ray tracing and 3D slowness time coherence (STC) procedure is used to determine the ray path type of the arrival event and the reflector azimuth. The angle of incidence of the reflected arrival is related to the relative dip, and the moveout in 3D across the individual sensors is related to the azimuthal orientation of the reflector. This information is then used to produce a 3D structural map of the reflector which can be readily used for further geomodeling.
This new technique addresses several shortcomings in the current state-of-the-art sonic imaging services within the industry. Similar to seismic processing, the current sonic imaging workflow consists of iteratively testing migration parameters to obtain a 2D image representing a plane in line with the desired receiver array. The image is then interpreted for features, which is often subjective in nature and does not directly provide quantitative results for the discrete reflections. The technique presented here, besides providing appropriate parameter values for the migration workflow, further complements the migration image by providing dip and azimuth for each event that can be used in further downstream boundary or discontinuity characterization.
A field example is presented from the Middle East in which a carbonate reservoir was examined using this technique and subsequently integrated with wellbore images to provide insight to the structural geological setting, which was lacking seismic data due to surface constraints. Structural dips were picked in the lower zone of the main hole and used to update the orientation of stratigraphic well tops along the well trajectory. 3D surfaces were then created and projected from the main hole to the sidetrack to check for structural conformity. One of the projected surfaces from the main hole matched the expected depth of the well top in the sidetrack but two were offset due to the possible presence of a fault. This was confirmed by parallel evaluation of the azimuthal sonic imaging data acquired in the main hole that showed an abrupt change in the relative dip of reflectors above and below the possible fault plane using the 3D STC and ray tracing. Dip patterns from both wells showed a drag effect around the offset well tops, further confirming the presence of a fault. A comparison of the acquired borehole images pinpointed the depth and orientation of the fault cutting both wells to explain the depth offset of the projected 3D well top surfaces.
Kumar, Rajeev (Schlumberger) | Al Busaidi, Salim (Schlumberger) | Al Ghafri, Ali Maayouf Dhafyiar (Schlumberger) | Al Amri, Aryaf (Schlumberger) | Uwe, Jonathan S. (Petroleum Development Oman) | Khaldi, Saud (Petroleum Development Oman)
The gas accumulation field under review is located in a highly stressed geological setting with tight sandstone reservoir overlain by wellbore instability prone formations. Drilling vertical wells over time became challenging with depleted sandstone reservoir requiring lower mud weight than required to minimize breakouts in overlying shale formations (Barakat, Mabrouk, Al Bashair and Miqrat). There was increase in drilling BHA held ups, logging tool stuck and NPT in recent wells. Hydraulic fracturing jobs were performed to obtain enhanced flow through the tight reservoir which itself increases cost for the wells. With increase in production requirement, horizontal wells were introduced to increase reservoir length which posed higher risk of wellbore instability in build-up section through shale formations and risk of differential sticking in long depleted open hole reservoir section.
A geomechanics model was constructed to represent the state of stress and mechanical properties of the overburden and reservoir to conduct wellbore stability analysis and simulate shear failures in offset wells for the mud weights used. Laboratory measured mechanical properties, closure pressure and breakdown pressure from hydraulic fracturing jobs, leak-off tests and drilling records collected from the offset wells were used to calibrate rock strength and stress profile. Wellbore stability analysis showed tendency of breakouts in shale formations with the mud weight used in vertical wells. Vertical pilot holes are usually drilled with 12.5kPa/m-12.7kPa/m. With increase in wellbore inclination, the mud weight requirement will increase by 0.8kPa/m-1.4kPa/m depending on the build-up inclination. Review of pilot hole sonic data showed anisotropy in the shale formations. Drilling in minimum horizontal stress direction as per plan would require higher mud weights (by 0.4-0.6kPa/m) than drilling parallel to maximum horizontal stress direction.
The geomechanical study helped in taking a number of critical decisions in the well design including the overburden shales and sandstone reservoir to be drilled in different open hole sections. This will enable weak shales to be drilled with higher mud weight in the range of 12.9kPa/m-13.9kPa/m to mitigate risk of stuck pipe in build-up section. Further, 7inch liner should be set to isolate build up section prior drilling the depleted reservoir with 10.6kPa/m-10.8kPa/m to minimize reservoir damage and differential sticking. Hole cleaning in critical build up section was addressed through proper mud additives to reduce torque and drag due to additional cavings as a result of breakout occurrence.
Findings from geomechanics study helped to minimize wellbore instability through key decisions on mud weight, kick off depth and BHA type during drilling operations. Both the build-up and reservoir sections were drilled successfully with minimum drilling related NPT. The mud weights were increased in steps based on field observations with the Geomechanical study results as guidance. This helped to maximize rate of penetration while reducing overbalance pressure across the overburden and reservoir sections.
Naidu, Nakireddi. A. (Petroleum Development Oman) | Hinaai, Qasim (Petroleum Development Oman) | Ismaili, Ibrahim (Petroleum Development Oman) | Smit, Jeroen (Petroleum Development Oman) | Youssef, Hamada (Petroleum Development Oman) | Hendra, Suhendar (Petroleum Development Oman) | Kumar, Rajeev (Schlumberger)
In the quest to achieve higher production, horizontal wells are being drilled in PDO concession area located in the Sultanate of Oman. The goal is to link a number of tight sand gas accumulations to central production facilities. Troublesome formations, including a variety of layered silty-shales (Al Bashair, Miqrat), and a depleted gas bearing sandstone formation (Amin), pose a huge challenge for wells drilled at high inclinations in high stressed environment. Earlier exploration and appraisal wells encountered stuck pipe, wide breakouts and hole cleaning incidents while drilling through those formations. The high risk of wellbore instability in accessing the reservoirs with horizontal well drilling threatened the commercial viability of the project.
This paper describes how a geomechanical study was used to mitigate wellbore instability in the decision making process during drilling operations of the horizontal wells in one of the Clusters. The geomechanical study output helped to select specific mud weights and to plan casing points in order to drill the critical landing and horizontal sections through breakout prone Ghudun formation and the 450m-500m thick silty-shales (Al Bashair, Miqrat) overlying the depleted sandstone reservoir.
A Mechanical Earth Model was constructed to represent the state of stress and mechanical properties of the overburden and reservoirs. The model incorporated data from a number of sources including laboratory-measured mechanical properties, closure pressure and breakdown pressure from hydraulic fracturing jobs, leak-off data and drilling records from the earlier vertical and high angle wells. Examination of the stress profiles showed considerable horizontal stress anisotropy and breakouts in Miqrat formation. Rock mechanics test data suggested anisotropic elastic and rock strength properties as confirmed by sonic anisotropy. This suggested that anisotropic Young’s modulus and rock strength properties vary between 10% and 15%. These anisotropic properties were used in the wellbore stability analysis.
The geomechanical study helped in making a number of critical decisions in the well design including the decision not to drill the Miqrat and Amin formations in one section as was done previously in high angle wells. This will allow the drilling of the highly stressed Miqrat formation with mud weight in the range of 12.8 kPa/m to 13.1 kPa/m to mitigate breakouts, stuck pipe, and to drill depleted Amin reservoir with mudweight of 10.8 kPa/m. Lower mud weight in Amin reservoir would minimize reservoir damage and improve ECD management with proper hole cleaning. Risk of mud losses and differential sticking in depleted Amin formation were reduced with proper mud formulation and rheology. BHA design was optimized while landing inside Amin reservoir to mitigate stuck pipe due to mud overbalance in the silty-sandstone layers in deeper Lower Miqrat formation.
The Amin reservoir section could be drilled safely as per the planned well path. In horizontal sections, the CBL’s are generally very poor in spite of precautions and good cementing practices were followed. Coupled with good cementing practices and planning, 100% cement bond log was achieved. This resulted in higher than expected production from the well with very encouraging results overall.
In the quest to achieve higher production, extended reach drilling (ERD) wells are planned to be drilled in the Bassein cluster, offshore India, threatened by high risk of wellbore stability after severe hole problems drilling low-angle exploration and appraisal wells. The key to successful drilling is to predict optimal mud weight windows for safe and stable ERD wells with a casing plan to drill the critical buildup section from 30° to 75° through overlying shales. The in-situ stress profile is built and further calibrated with closure pressures obtained during extended leakoff tests and stress testing with the modular formation dynamics tester. Rock mechanical properties are estimated to history match actual failures with predicted failures using the geomechanical model and mud weight used while drilling.
Reported cavings and stuck tool incidents in shale formations are at depth intervals where the estimated breakout mud limit exceeds the mud weight used during drilling of offset wells. There is variation of rock elastic properties like Young's modulus and Poisson's ratio with direction in shale. Intermediate lower-strength coal and shale layers are seen in the Panna sandstone against overgauged hole condition observed in offset wells. Stable mud weights to avoid breakouts are in range of 11.6 to 12.5 ppg depending on well azimuth and deviation across different shale layers. Variations in minimum stable mud weight are in the range of 0.3 to 0.5 ppg based on well azimuth with reference to minimum horizontal stress direction from same platform. Even with depletion of 1.2 ppg in hydrostatic limestone, the minimum mud weight required to safely drill the horizontal section is 8.7 to 8.9 ppg due to lower- strength layers. Well deviation should remain same in the 12.25-in. section to avoid hole cleaning issues in shale. The breakout-mud loss window varies between 1.3 and 1.8 ppg at high well deviation in the 12.25-in. section. The 20-in. casing shoe plan was modified by setting deeper by 100 to 150 m to obtain a higher mud weight window. Lower core recovery at the top of the target limestone reservoir coincides with overgauged hole conditions seen across all offset wells. The local normal fault regime identified against regional strike-slip geological setting.
The modifications resulted in significant reduction of nonproductive time with no lost-in-hole incidents and time savings of 1 week on each ERD well compared to offset wells. The good hole condition made it possible to acquire formation pressure measurements across the field to update the reservoir model and understand the structural connectivity of different target layers.
Core-calibrated petrophysical rock typing for gas rate deliverability profiling, coupled with field-calibrated mechanical stress models, represents a significant step forward in optimizing the value of hydraulic fracture stimulation in the Khazzan field unconventional tight gas reservoir. Our Mechanical Earth Model (MEM) is an important component of the integrated workflow currently being used for selecting intervals for successful hydraulic fracture initiation. When incorporated into an integrated subsurface performance prediction strategy, this technology enables optimization of well targeting, increased reserve recovery, and capital efficiency.
The interaction of regional tectonics and local lithology controls the stress profiles of the layers in the Barik tight gas reservoir in the Khazzan field. Core measurements show a significant effect of rock fabric and diagenesis on effective gas permeability, elastic properties, and rock strength. The ability to incorporate lithology, rock fabric, and pore geometry in our dynamic to static calibrations provides new insights into our predictions of rock mechanical properties and reservoir quality, which are used to obtain calibrated "fracture initiation" profiles from core, log, and downhole stress measurement information.
The MEM is calibrated using an integrated wellbore stability analysis and horizontal stresses are refined by honoring the observed borehole breakouts, formation breakdown and closure pressures. The models show that the adjacent layers in Khazzan field are under higher stress than the pay zones, which enhance fracture height containment and lateral fracture penetration. Previous studies have suggested that there are unequal horizontal stresses which are potentially due to tectonic effects. However, in some cases the magnitude of stress variation and reversal in stress-ordering across minor depths is problematic and confirms the pitfalls of oversimplified assumptions and models used in stress profiling in unconventional reservoirs. This work highlights the magnitude of stress variations within the formation and illustrates an integrated methodology to assist the decisions on selecting hydraulic fracture locations.
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.