The drilling of thousands of unconventional horizontal wells in North America highlighted the impact of the landing zone on production, underscoring the importance of geosteering with the intention of staying in the most fracable rock. Unfortunately, the use of fast drilling motors combined with delayed logging tools, and insufficient data to quantify mechanical properties while drilling created multiple geosteering challenges. This paper describes a new technology that uses surface drilling data to estimate, in real time, the geomechanical properties needed to guide the steering of horizontal wells into the most fracable rock. The Mechanical Specific Energy (MSE) computed from commonly available drilling data such as torque, rate of penetration and weight on bit has been widely used to improve drilling efficiency. However, the more recent use of MSE for completion optimization has yielded conflicting results. This paper introduces the use of Corrected Mechanical Specific Energy (CMSE) where the friction losses along the drill string and wellbore are computed and accounted for in real time. CMSE is used to estimate, in real time, geomechanical logs and build a live geomechanical model that is used for steering into the most fracable rock. Once the drilling is completed, the frac stage spacing and cluster density is adjusted according to CMSE outputs which include pore pressure, stresses, and natural fracture index. The new approach was used on multiple shale wells where the geomechanical logs predicted from CMSE and subsequently estimated fracture index were validated with multiple data including image logs, microseismic, and elastic properties derived from seismic pre-stack elastic inversion. This technology represents a major step in completion optimization since it tackles the problem and provides the solution during the drilling phase. A major advantage of the new technology is its ability to be deployed on any rig without the use of additional surface gauges, sensors or downhole measurement tools, avoiding additional costs and risks of potential wellbore problems. Additional benefits of the technology include: no on-site personnel or permits, the use of existing real time drilling data streaming services to quickly steer in the fracable rock, and having completion design immediately following the completion of drilling. This contrasts dramatically with alternative completion optimization methods for which data delivery, analysis, planning and design can take many weeks.
The Nong Yao field is operated by Mubadala Petroleum on behalf of the G11/48 block concessionaires with KrisEnergy and Palang Sophon Limited. Nong Yao recently commenced production following a successful development drilling campaign, which was extremely challenging due to subsurface uncertainties. The subsurface team adopted an innovative method of well sequencing and optimization of targets, such that every well drilled is used to de-risk other wells, in order to avoid costly additional appraisal drilling. The key methodology involved a deep understanding of the exploration and appraisal data gaps and as a result the uncertainties / limitations of the static and dynamic models. A field development plan was developed that could achieve additional appraisal objectives, and in doing so, de-risk other wells as the development was executed. Uncertainties that the team sought to mitigate included structural uncertainty (due to shallow gas effects), fluid contacts and fluid type uncertainty, sand distribution and connectivity uncertainty and also uncertainty in the aquifer extent and degree of pressure support expected. This information was gathered by planning deeper high deviation development wells with complex 3D trajectories, that could intersect multiple reservoir sands and provide the formation evaluation and well landing points for later horizontal development wells in shallower reservoirs. Achieving appraisal objectives while drilling both in the static and dynamic sense, helped in optimizing well locations and led to the cancellation of multiple water injection wells, which were not required as drilling indicated better aquifer and pressure support than initially expected. This led to substantial savings in well costs and enabled rig slots to be utilized for production wells rather than unnecessary injection wells. Key technologies were used to achieve appraisal objectives. A high build rate hybrid RSS tool was used to deliver complex 3D well profiles and land wells above oil-water contacts while maintaining high ROP and wellbore quality. The deep resistivity distance to boundary LWD tool ensured horizontal production wells stayed in the reservoir sands and also helped to map the top and extent of structures, improving reserve calculations and reservoir simulation. In key wells the use of ultra-deep resistivity for reservoir mapping combined with the LWD near-bit triple combo, helped in mapping the reservoir prior to entering it, eliminating the requirement for separate pilot wells. Innovative formation pressure acquisition methods were used to better understand reservoir connectivity and depletion and to determine whether injection wells were required. It also helped to reduce uncertainty on fluid contacts, providing better accuracy and optimizing well positioning. The impact was that more marginal oil pools could be developed with a higher degree of confidence. The clear value of these innovations was a reduced overall development cost and wells better placed for recovery and production. With lower development costs, more reservoirs of this nature in the Gulf of Thailand can become viable to develop, which has a significant impact on the future of Thailand's oil and gas industry.
The accurate prediction of the depth of top carbonate while drilling carbonate reservoirs is important to avoid losses and well control problems. This can have a significant financial impact. This paper demonstrates the use of innovative look-ahead VSP technology in Vietnam to refine depth prediction of the top of carbonate ahead of the bit for accurate geo-stopping. An offshore exploration well was being drilled in an area with drilling challenges. This was the first well in the field and lacked offset well velocity information, so there was a high degree of depth uncertainty to the top of the carbonate target from surface seismic interpretations, making drilling operations risky. An intermediate VSP was requested to look for reflections ahead of the intermediate TD using Schlumberger VSI1 tool. The VSP data was acquired in open and cased hole using an air gun cluster as the seismic source. The drilling program required the casing to be set immediately above the top of the carbonate. By acquiring an intermediate VSP, the depth uncertainty was reduced and the target depth prediction was refined. This was achieved using the look-ahead VSP technique, from which the acoustic impedance and velocity ahead of the bit was estimated. This was combined with time-depth from the VSP data over the logged interval to help refine the predicted depth to the top of the carbonate. This was used to optimize the depth at which the casing was set. The error range for the top carbonate depth from the surface seismic interpretation was +/-50m. The final prediction depth from the VSP interpretation is 6m shallower than the actual carbonate reservoir. Guided by the inverted acoustic impedance log and velocity ahead of the bit from look-ahead VSP, a further 100m was safely drilled before setting the casing. The casing point was set successfully without penetrating the carbonate. The intermediate VSP results helped to decide drilling ahead in a safe manner with confidence, after setting the casing before penetrating the carbonate target.
The Nong Yao Field in the G11/48 concession is operated by Mubadala Petroleum on behalf of the other concessionaires KrisEnergy and Palang Sophon Limited. Nong Yao recently commenced production following a successful development drilling campaign, which was extremely challenging due to subsurface uncertainties. The subsurface team adopted an innovative method of well sequencing and optimization of targets, such that every well drilled is used to de-risk other wells, in order to avoid costly additional appraisal drilling. The key methodology involved a deep understanding of the exploration and appraisal data gaps and as a result the uncertainties / limitations of the static and dynamic models. A field development plan was developed that could achieve additional appraisal objectives, and in doing so, de-risk other wells as the development was executed. Uncertainties that the team sought to mitigate included structural uncertainty (due to shallow gas effects), fluid contacts and fluid type uncertainty, sand distribution and connectivity uncertainty and also uncertainty in the aquifer extent and degree of pressure support expected. This information was gathered by planning deeper high deviation development wells with complex 3D trajectories, which could intersect multiple reservoir sands and provide the formation evaluation and well landing points for later horizontal development wells in shallower reservoirs. Achieving appraisal objectives while drilling both in the static and dynamic sense, helped in optimizing well locations and led to the cancellation of multiple water injection wells, which were not required as drilling indicated better aquifer and pressure support than initially expected. This led to substantial savings in well costs and enabled rig slots to be utilized for production wells rather than unnecessary injection wells. Key technologies were used to achieve appraisal objectives. A high build rate hybrid RSS tool was used to deliver complex 3D well profiles and land wells above oil-water contacts while maintaining high ROP and wellbore quality. The deep resistivity distance to boundary LWD tool ensured horizontal production wells stayed in the reservoir sands and also helped to map the top and extent of structures, improving reserves calculations and reservoir simulation. In key wells the use of the ultra-deep resistivity tool for reservoir mapping combined with the LWD near-bit triple combo, helped in mapping the reservoir prior to entering it, eliminating the requirement for separate pilot wells. The impact was that more marginal oil pools could be developed with a higher degree of confidence. The clear value of these innovations was a reduced overall development cost and wells better placed for recovery and production. With lower development costs, more reservoirs of this nature in the Gulf of Thailand can become viable to develop, which has a significant impact on the future of Thailand's oil and gas industry.
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