Summary In this paper, we present a field example where pressure and distributed-temperature measurements enabled understanding of reservoir characteristics and fluid movement causing production hindrance in an offshore horizontal well. The field example has a horizontal well in the South China Sea that was completed as an openhole monobore oil producer using a slotted liner. The well began production with an initial oil rate of 1,800 B/D. Oil production quickly dropped to 1,000 B/D and gradually declined to 200 B/D. During this period, the gas/oil ratio (GOR) steadily increased from 200 scf/bbl to 2,200 scf/bbl. To arrest production decline, a chemical treatment was conducted to remove suspected emulsions and polymers assumed to have been deposited during drilling. Immediate post-treatment production increased to 3,700 B/D, but dropped dramatically and stabilized at pretreatment rates soon after. Formation of emulsions and asphaltenes were believed to be the cause of the production decline. However, with inadequate information, the diagnosis was inconclusive. Consequently, another chemical treatment was conducted and this time, a fiber-optic-enabled coiled-tubing (CT) string along with real-time bottomhole-pressure and temperature gauges were used to acquire distributed temperatures and pressures of the entire horizontal section of the wellbore. Results of the pressure survey revealed that the well was receiving insufficient pressure support from the water injector, which was causing gas-cap expansion. The distributed-temperature survey indicated excessive gas production from the toe of the horizontal section as a result of this expansion, thus limiting liquid production. The combination of gas rates with oil and water production has also created tight emulsions, further hindering production performance. It was concluded that the high gas production from the toe could not be selectively shutoff or controlled in the horizontal openhole slotted-liner completion to perform an effective stimulation program and treat the tight viscous emulsions.

Coiled tubing has been widely used worldwide to perform perforating and zonal isolation operation due to the ability in intervening highly deviated and long section of horizontal wells under live condition, where slickline and E-line have difficulties. This paper presents case history of coiled tubing perforating and zonal isolation evolution in infill well at Resak field, one of the gas field operated by Malaysia National E&P Company, Petronas Carigali Sdn Bhd. Since the beginning of Resak Field production, coiled tubing has been used to perforate numbers of infill wells with low success ratio. The reservoir characteristics with high formation pressure and BHT followed by high CO2, H2S production and improper well clean up contributed in the increase of operational risks and challenges. Several failures reported in the past was carefully analyzed to determine the actual root cause prior to coming up with the proper job design and operational procedures. CTU with 1.5″ CT reel was used to convey 140 ft of 2–7/8″ gun due to crane and platform deck loading limitation. The small CT size and large gun conveyance required extra precaution since the presence of gun shock during perforation may affect the CT integrity. Therefore supporting perforating software was run in advanced to optimize gun selection where both operational risks and production objectives were taken into consideration. Coiled tubing forces simulation was also used to determine the ability of the gun assemblies to be safely conveyed into the target sands. In addition to that, one of the unique features from the gun assemblies was the selection of electronic firing head over a conventional or standard drop ball mechanism. This tool utilized coded sequence created fromvariation of surface pump rate to generate its firing command, providing reliable gun activation where as the drop ball mechanism in the past was found to have some operational difficulties. Lastly, this paper also mentions the proper selection of zonal isolation method that can withstand the wellbore condition, providing adequate isolation whilst able to be retrieved for future production requirements. The result of those engineering studies managed to overcome the operational failures in the past and at the same time was able to meet the production objective. Project Result After performing the coiled tubing operation by isolating J10.2 with inflatable bridge plug and perforating J10.1 with deep penetration gun, the well managed to be produced at 22.7 MMSCF/D & stabilized at 48 MMCSF/D (23 % choke size) with total gain of 41MMSCF/D which was higher than the expected gain of 35 MMSCF/day (Figure 1). Currently the well is the highest producing well in Resak field with stable production at 49.8 MMSCCF/D. Introduction This gas producer well was drilled in March 2004 and completed in 4–1/2″ monobore completion by penetrating the reservoir of J-10.2 & J-10.1, with J-10.2 being perforated leaving J-10.1 un-perforated (Figure 2). Based on the log analysis, J-10.2 sand has 6.8m TVD net pay with average effective porosity of 15% and permeability of 26md followed by water saturation of 37.7%. After 2 years of production, gas rates started to decline from 18 MMSCF/D down to 7 MMSCF/D with gradual increase in water gas ratio up to 10 BBL/MMSCF. This phenomenon was also supported by adjacent well performance which was shut in due to high water production. Nitrogen lift operation was performed on adjacent wells, but failed to sustain the production. Despite the decline trend, remaining gas reserves are still attractive and having potential to be produced in the future at 85% recovery factor.

In this paper, we present a field example where pressure and distributed temperature measurements enabled understanding of reservoir characteristics and fluid movement causing production hindrance in an offshore horizontal well.

Many retrograde condensate gas wells in field A, located offshore Malaysia, are underperforming or even idle because of calcium carbonate scale deposition and near-wellbore condensate banking. Previous treatments were performed without any adjustment of fluid placement across the multiple fractured zones due to the lack of technology enabling real-time downhole monitoring. Fluids could, therefore, be lost into depleted or high-water-cut intervals, leading to suboptimal treatment.Distributed temperature sensing (DTS) technology through optical fiber installed inside coiled tubing strings mitigates the risks related to blind acid pumping. The technology makes it possible in real time to monitor and adjust fluid placement and diversion efficiency to squeeze acid into target zones and maximize the treatment success.The first worldwide implementation of sandstone matrix acidizing using the DTS technology was performed on a well completed with four perforated and propped fractured zones. The main treatment fluid was designed to remove both types of formation damage: organic acid would attack the scale and alcohol would eliminate the condensate banking. The first challenge was the cleanout of hard carbonate scale from the wellbore, which was performed with a bottomhole assembly composed of a high-pressure rotating jetting tool and a real-time fiber-optic tension-compression sub enabling the coiled tubing unit operator to maximize the slack-off on scale and facilitate its removal. The second challenge was the depleted upper perforated and propped fracture interval detected by the DTS. If diversion was inefficient, all fluids would get lost into the upper zone. A diverter fluid system formulated with degradable fiber blended into viscoelastic-surfactant-based fluid was optimized based on expected downhole conditions, and two stages were successively squeezed into the highly permeable (130-Darcy) depleted upper interval before getting a good signature on the DTS surveys showing that this zone was temporarily plugged and that the main treatment fluid would be squeezed into the lower target zones.The post-treatment gas production was double what was expected. A memory production logging tool was run after the job. This confirmed the crossflow to the upper depleted zone during shut-in and showed 86% gas production from the two bottom intervals, which demonstrates the effectiveness of both the innovative stimulation process with DTS and the diversion with degradable fiber.

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