This paper presents a more holistic approach to compare the drilling economics of Synthetic Oil Based Mud (SOBM or SBM) versus Water Based Mud (WBM) in onshore development drilling in India. Here, a key parameter which has been incorporated in the economics is the mud re-use and overall consumption trend of SBM versus WBM, which has been analyzed from statistical data across 200+ wells and quantified into overall cost savings with SBM estimated across roughly 500 development wells drilled. The surface holes in all the development wells were drilled with WBM instead of SBM to avoid contamination of shallow water aquifers. Hence, the performance evaluation of SBM was limited to intermediate and production holes only, which were drilled with SBM. Also, past exploration and appraisal wells had used WBM for drilling these hole sections. A key parameter calculated from statistical data was average mud consumption (barrels per meter drilled) for SBM and WBM. The mud consumption of SBM and WBM is expected to differ because theoretically SBM can be re-used across greater number of wells compared to WBM. The average mud consumption was separately calculated for different hole sizes to better analyze the effect of hole size on mud consumption. The actual cost incurred with SBM application in development wells was calculated. Next, cost for drilling these wells with WBM was estimated using mud consumption (barrel per meter) data obtained from exploration/development wells. These two cost scenarios were compared to arrive at the net cost savings with SBM compared to WBM. A maximum cost savings upto ~10 MMUSD (for various sensitivities especially SBM cost per barrel) is estimated across 500 wells in spite of the higher contracted costs of SBM (cost per barrel) when compared to WBM. The maximum cost saving of ~10 MMUSD corresponds to anticipated reduction in base oil cost in the current crude market. The savings with SBM are mainly attributed to the fact that SBM can be theoretically re-used infinitely moving from one well to the other while the WBM can be re-used for a limited number of wells. This cost model excludes any savings on part of SBM due to improved hole conditions and resultant reduction in drilling non-productive time. SBM system minimizes drilling problems due to good clay inhibition, enhanced hole cleaning, lubricity additionally SBM is least effected by contamination. However, the higher cost per barrel of SBM and associated environmental concerns normally act as deterrents for operators to choose SBM for planning their wells. This paper provides clarity on the perception "SBM is costlier to WBM" and reinforces the recommendation to use SBM for drilling operations from an overall cost perspective.

The paper presents a case study on adopting an economics driven novel approach to directional well planning and drilling a horizontal well in a single well FDP (field development plan) for a marginal field in onshore India. The paper highlights the successful drilling of 8-1/2″ landing production section with DLS > 7 deg/30m followed by the 8-1/2″ horizontal lateral. The feasibility of achieving high DLS well trajectory using basic directional tools and associated hole problems with their mitigations are addressed in the paper. Low crude price resulted in marginal economics for the above FDP. To improve economics, the capital expenditure had to be minimized (by utilizing existing well pads and production facilities) and maximize oil production (by drilling horizontal wells). Hence, constrained surface locations and fixed subsurface targets resulted in complex well trajectory (DLS>7). The Trajectory was finalized after multiple iterations to ensure that it is meeting requirements of deep set artificial lift, free of collision threats and also meeting the geological objective of placing the well in a thin reservoir with defined GOC and OWC. The final well design included one 12 ¼″ surface section with 9-5/8″ casing and 8-1/2″ production hole with 7″ casing to TD (~1800m MD). The well was initially planned with special RSS tool which could achieve high DLS, but the cost and lead time were the contra-indicators. Hence, the 8-1/2″ hole was planned with two BHAs. The build and land section was planned with motor (1.6 deg bend and rpm limitations) and tricone bit BHA to build from 9 deg to 90 deg inclination with a DLS of 7 deg/30m in 400m closure. The horizontal lateral was planned with RSS BHA and PDC bit including density image LWD for geosteering. To minimize hole sections for cost reduction, the landing and horizontal section was combined in a single hole which increased risk associated with wellbore stability, hole cleaning and casing running. The risks were suitably addressed through in-house geo-mechanics inputs, application of ERD procedures & real time T&D monitoring With no offset well data (in onshore India) to substantiate the possibility of achieving high DLS trajectory, the motor and tricone bit BHA successfully achieved the desired trajectory with max DLS ~11deg/30m and without any hole problems. The well was successfully landed and placed in the reservoir. The operator gained significant confidence in understanding of drilling high DLS wells without expensive drilling tools