Mature field necessitates drilling high angle and horizontal wells in order to improve wells productivity, reduce water coning and tapping multiple reservoirs. The operating company has endeavored to convert many of the Vertical wells in its mature fields into High angle and Horizontal wells by Side Tracking, primarily to reduce well cost and overcome restrictions in obtaining clear surface locations. Shale instability related problems were experienced in many Side Track wells in the buildup section. The whole deviation used to be ranging from 62 degrees on the top to 70 degrees on the bottom. The old wells used to be completed traditionally with a DLS of 5 – 5.5 leading to stuck pipe, hole collapse, multiple wiper trips, casing short landing etc. The operating company after extensive techno-economic evaluation has implemented a new and novel drilling technique to allow side tracking from an existing well, with inclination in the hole as low as possible, and land the well successfully with high dogleg severity. The new approach managed to reduce the deviation against the problematic formation to 50 degrees with a high dog leg severity up to 12 degrees / 100 feet. A high Build rate Rotary Steerable tool was used to reduce the measured depth and in some cases reduced inclination when drilling through unstable shale layers overlying the target formation. The High Build Rate tool also reduces the Vertical section thereby landing the well closer to its original hole reducing uncertainties in Landing. The Rotary Steerable was preferred due to its inherent advantage of continuous rotation that reduces differential sticking and enhances hole cleaning. Deep Kick Off increases deliverability of the depleted producer well by enabling placement of ESP Pumps at a deeper depth and overcome deferent formation with defiant pressure which improve mud weight management and overcome the stuck pipe problems in the shale zone by cutting through this shale with a low Inclination. It also enabled shorter measured depth, closer successfully landing and reduced open hole exposure time. Finally, the cost saving in this project can be summarized in reducing the buildup section by 45% which can be translated into a saving of more than 70 K USD per well.
Mauddud reservoir in Sabriyah field is a giant heterogeneous carbonate reservoir discovered in 1950s. The field is on production since 1957 with natural depletion since it has no aquifer support. Overtime, with continuous production there has been a decline in reservoir pressure which affected the field productivity. This paper presents successful field development strategies on multi-discipline approach, integrating sub-surface domains through comprehensive planning studies and high end geo-steering technologies with objective to arrest the pressure decline and sustain oil productivity from the Sabriyah Mauddud giant carbonate reservoir. For optimum exploitation of giant Sabriyah Mauddud reservoir, KOC is currently performing high volume producer and injector horizontal wells drilling campaign. Meticulous predrill planning integrated with advance geo-steering technologies such as Multiple Bed Mapping Distance to Boundary (DTB), Azimuthal Density and Ultra High Resolution Resistivity Image helped KOC to get best results from horizontal wells, not only in short term, but more importantly long term. An effective horizontal well would minimize amount of attic oil, delay water production and hence increase ultimate reservoir recovery. To reduce overall well cost, minimize well bore instability and maximize well production, a very innovative strategy was adopted to drill medium radius 8.5" curve sections with high dog leg severity using special drilling technologies. The Mauddud reservoir varies in property and thickness in different segments of the field, therefore tailored-to-fit drainholes strategies were adopted to exploit the massive Sabriyah carbonate reservoir efficiently. The new strategy of high dog leg medium radius ensured footage reduction by almost 50% in build section. Lower inclination through top shale sections ensured better wellbore stability and smoother drainhole. Reduction in footage meant the curve sections were drilled in less than 48 hours in a single run and resulted in huge cost savings. Another major achievement of this strategy was that landing point was positioned closer to mother bore (for sidetrack) because of reduced horizontal displacement by approx. 60%. After implementing drainhole strategies tailored to address unique challenges of particular segment of the field, horizontal producer and injector wells were successfully placed on top and bottom part respectively of Mauddud reservoir with desired exposure length, resulting in maximum reservoir contact and minimize water coning. An overall improvement of 30% in production rate and maintained water cut rate recorded on applied horizontal well case studies compared to non-horizontal wells. Consistent application on these field development strategies would be beneficial in long term by achieving increase of ultimate field recovery. This paper provides insight on successful application of innovative field development strategies to optimize production from Sabriyah Mauddud reservoir. Field specific development plans along with innovative landing strategy and proactive geo-steering with multi boundary mapping along with high resolution resistivity imaging tools minimize geological risk and helped to achieve horizontal well and field development plan objectives. Similar approach can be adopted to sustain long term oil productivity from this type of complex carbonate reservoir.
Most of the fields in the northern part of Cambay basin are characterized by heavy crude. To enhance productivity, Insitu combustion had been practiced in this belt over a long period of time. The in-place combustion of hydrocarbon also produces residual gases called Flue gas, which in time migrates and accumulates towards structural highs. The buildup of flue gas pockets towards reservoir top slowly began affecting production in this belt with conventional producers showing premature gas cuts. This created the need for an effective change in strategy that would yield gas free production. The following paper illustrates a very challenging field development strategy deployed in field Z, located in this belt to tackle complexities of flue gas build up in reservoir.The strategy firstly involved changing the planned drainhole geometries in field Z from vertical and near vertical to horizontal. Horizontal producers has reduced coning and cusping effect and enhanced sweep radius. The main challenge with this strategy was to place these producers at safe distance from the gas pockets at top. To handle this challenge, LWD and "Distance to Boundary" technology was deployed for the first time in this field.A combination of gamma ray, resistivity and density-neutron data would help to track the flue gas zone while drilling which could be used to land the build section at a safe distance below gas caps. "Distance to Boundary" technology would be used during drainhole to detect the reservoir bottom and keep trajectory at about 2-3m from bottom. Placing drainhole close to reservoir bottom would ensure a safe distance from gas pockets throughout the drilled interval.This strategy worked effectively with 3 wells been drilled till now in field Z with very good production rates without any gas cut.
Field X is located in the northern part of Cambay basin, western onshore India. Sand-1 is the main reservoir unit in this field. Primary recovery is low here because Field X is located in the region's heavy oil belt. To increase the recovery factor, thermal EOR technique - Insitu Combustion, has been implemented in various parts of this heavy oil belt. Insitu combustion reduces oil viscosity but at the same time produces residual gases. These residual gases, called "Flue gas", accumulate as pockets in the reservoir top. The thermally altered low viscous crude can be produced efficiently through horizontal drainholes by maximizing reservoir contact and sweep radius. Placing a horizontal drainhole in this field is a challenge in itself because the drainhole has to be maintained at a safe distance from the flue gas pockets on top to prevent premature gassing out and also at a safe distance from bottom shale. As a solution to this challenge, "Distance to Boundary" (DTB) technology along with LWD was introduced for the first time in Field X in Well X. "DTB" technology detects the resistivity contrast at a shale-sand interface and maps the shale boundaries while drilling. The well was landed ~10m below reservoir top using LWD measurements to maintain a safe distance from flue gas pockets on top. It was decided to place the drainhole about 3m above reservoir bottom to stay away from bottom shale. The final result was a spectacular success with 311m of drainhole drilled with 100% stay in target reservoir zone. "DTB" technology tracked lower shale from ~3m and trajectory was maneuvered in conjunction with the structural changes to maintain an average distance of 3m from bottom. LWD data was used to verify sweet zone throughout the drilled interval. This paper illustrates an exemplary case study which opens new and exciting possibilities for application of LWD and "-DTB-" technology in field X for further field development plans.
The primary reservoirs in the Greater Burgan Field in Kuwait is the Lower Cretaceous Burgan Sands. Burgan sands are divided into five major units which consist of stacked, massive fluvial channels and some units mostly consist of delta distributary channels and bays in a tidal delta setting grading to shallow marine. These are discontinuous both laterally and vertically. Channel sand geometry in geosteering perspective often sums up to discontinuous patches of sand lenses at differing stratigraphic levels. Maximizing net pay in a channel sand reservoir is known to be a very challenging task for the geosteering domain. Navigating a drainhole through such geometry requires precision geosteering technologies that can map multiple reservoir boundaries with high accuracy enabling precise forward designing wellbore trajectory with respect to the dynamic reservoir geometry. Deep directional distance to boundary "DTB" technology revolutionized the whole concept of geosteering in this regard by enabling proactive geosteering for the first time in industry. Introduced in 2005, it features the capability of detecting reservoir boundaries up to 15ft around the wellbore and achieved great success all over the world through proactive geosteering in thin reservoir layers and maximizing the percentage reservoir contact. However, this technology is limited to mapping only 2 layers, above and below the tool, up to a distance of 15ft around wellbore. It cannot detect a third layer beyond the two layers surrounding it. High definition deep directional multi boundary detecting technology is a noble advancement on the first generation Distance to Boundary technology. With significantly improved signal to noise ratio, supported by a robust and new multilayer stochastic inversion algorithm that incorporates a whole gamut of measurements, principally from 3 firing frequencies (100kHz, 400kHz and 2Mhz), this technology extends its capability by mapping multiple boundaries up to 20ft around the wellbore. This paper examines a case study from the Greater Burgan Field, Kuwait where the extended capability of this technology has yielded exemplary results in navigating wellbores through very complex channel sand geometry with very sharp local dip changes and varying thicknesses. Extreme geosteering is finally made possible with this fit-for-purpose technology in complex subsurface environments, lowering construction risk while maximizing net pay for each well drilled.
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