The potential for gas hydrate production is always present in deep water operation. It will cause hazardous impact if gas hydrate plug formed during drill stem testing. This paper takes a case from south china sea, with about 1500 meters water depth gas field, to describe hydrate prediction and prevention during drill stem testing. This paper will discuss:1. The method to predict what depth the gas hydrate may be formed in the testing string. 2. Procedure optimization to reduce the risk of gas hydrate 3. Key technique to prevent gas hydrate formation 4. The result of executionThe study indicated it is viable technique to predict gas hydrate formation by simulating fluid flow in testing string, as well as hydrate inhibitor selection and the amount of inhibitor can be simulated and optimized. The procedure of one flow period and one build-up period reduced the operational risk to form gas hydrate. Downhole methanol injection and closely production monitor prevented gas hydrate production. As a result of this practice, six times of DST has been successfully implemented in deep water gas field in south China sea. The well productivity and fluid sample has been accurately obtained for future overall development plan.The result of this study are most applicable to DST design in deep water gas field, however, they also may also be appropriate for shallow water DST.

This paper presents a case history on new sandstone acidizing technology using a nonhydrofluoric formulation to successfully treat a high carbonaceous sandstone formation. The improved understanding of the chemical complications of hydrofluoric (HF) on dirty sandstones led to the design of a nonhydrofluoric treatment on the high carbonate content (dirty) sandstone formation. Previous treatments using various formulations of HF acid failed to remove the high skin associated with several wells in this formation. A new approach was taken to identify the damage mechanism and evaluate damage removal options based on the formation mineralogy. This approach analyzed the potential chemistry risks associated with using HF type treatments in the presence of particular mineralogies and temperatures. The new approach also used logging and reservoir modeling technology to forecast the estimated production profile of the complex multilayered formation. Candidate wells were identified by comparing the forecast production profile potentials to the surveyed production profiles based on production logging (PLT) of the prescreening candidates. The final treatment candidate was then selected for the trial of the new treatment formulation. The treatment was specifically tailored based on the identified mineralogy and encompassed the damage prevention strategies. The result was a 40% increase in oil production for the well, but a 2-fold to 10-fold increase for the treated zone, depending on pretreatment production assumptions. Introduction XJG oilfields are located offshore in the South China Sea around 130 km southeast of Hong Kong.1 The fields are composed of three geological structures named XJG 1, XJG 2 and XJG 3, the first one being discovered in 1984 and targeting sands from the mid-Miocene XH formation and finding up to 44 stacked reservoirs bearing black oil. Appraisal wells were drilled and tested; commercial production started in 1994 following the installation of two platforms. Oil gravity varies from 26° to 40° API, saturating unconsolidated sandstones with average porosity of 25% and permeability measured in a Darcy plus range. The formation is prone to produce sand, and typical completions at the beginning exhibited internal gravel packs inside a 9 5/8-in. casing, but recently shifted over to expandable sand screens in open hole making water control difficult to achieve. Reservoir pressure has been strongly supported by a bottom water drive aquifer, which has kept the pressure only a few psi below its original value. The water drive has helped to sweep hydrocarbons, but on the other hand, has also caused rapid breakthrough in high permeability layers. Electrical submersible pumps (ESPs) are used in all wells in the field to improve productivity and handle high volumes of water. Field average water cut at this stage is around 84% with a total field liquid production close to the limit of fluid handling capacity of the facilities. XJG reservoirs are being developed using two fixed platforms. As of this writing, all 24 available slots on platform XJG-2 have already been drilled and completed, while XJG-3 has one slot left available for an extended reach drilling (ERD) well in the near future. This situation limits the option of infill drilling to accelerate oil recovery. The combination of high permeable formation streaks and active aquifer accelerates water breakthrough in perforated zones, raising the average field water-cut. The oil production is near 85,000 BOPD while total fluid production is close to the 550,000 BFPD capacity of fluid handling and water disposal of the existing surface facilities on the platforms. Production logging is performed on a regular basis to monitor zonal fluid contribution. Reservoir zones are isolated by external packers and flowing through sliding side doors (SSD) valves. Water control is achieved by closing the SSDs to the high water-cut zones, but it is hard to determine exactly where the water is coming from or how much hydrocarbon has been left across the perforated intervals grouped in that zone.

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A brownfield new horizontal wells re-development project was initiated in mid-2012 to arrest the production decline rate of Panyu oilfield with average field water cut of 91% and to further increase its reserve recovery.The new horizontal wells campaign were targeting at the remaining less than 5m thin oil column with strong bottom water drive and the previously unexploited 2m thin layers reserves. However, the re-development and exploiting these targets present operational challenges with increasing complexity. Not only the horizontal well needs to be optimally placed within complex target zone, the lateral also needs to be placed as close as possible to the reservoir top to keep it away from the unknown current fluid contact.This paper features the best practices implemented to optimize the standoff between horizontal section and oil water contact that is very sensitive to well performance and reserve recovery. This includes precise landing with low incident angle and lateral placement within less than 0.5m window below the reservoir top utilizing the directional electromagnetic and wellbore imaging applications for detail reservoir profiles description and current OWC level identification while drilling.Multiple wells' field cases will be discussed in the paper based on 25 horizontal wells completed during the course of the project. Several key outcomes that have been observed during the execution and upon the completion of the well will be highlighted, including:-Clear identification of the reservoir geo-bodies and their interfaces including the current fluid contact level -Optimum lateral placement in the best position to drain the remaining hydrocarbon -Reversing the production decline trend and exceeding the cumulative incremental oil by 45% over the forecast.Finally, the authors conclude that significant oil reserve can remain in mature fields and be recovered through re-entry horizontal wells drilling program. The implementation of the best practices in operation is the key enabler to effectively place the trajectory in the best place to drain the remaining hydrocarbon that lead to maximizing the late-life value of a mature oilfield.

Water breakthrough (WBT) in the horizontal wells often leads to water flooding in the well, especially to those heavy oil reservoirs in reef limestone carbonate. The excessive water production from the hydrocarbon producing horizontal wells can adversely affect the economic life of the well, furthermore this could result in the well permanent abandonment. Nowadays, no effective methods of water control are available for the similar reservoirs, traditional water control methods have three technology barriers: (1) can not accurately locate the WBT positions;(2) difficulty of identifying the wellbore completion, fluid, and nearby formation conditions;(3) Not being designed to control water from new water breakthrough points. This paper shows a newly developed water control technology by using continuous Packed-off double water control technology (CPI). It was successfully implemented in a well of a fractured reef limestone oil field in South China Sea. This technology completely overcome the above shortcomings of traditional water control methods. The mechanism is to pack patent particles into the wellbore and near-wellbore fractures to create a double "artificial well wall". It suppresses radial and axial turbulence effectively. The operation procedure of CPI water control method is simple. It has been proven with lower cost and longer effective duration of controlling water, which can greatly increase oil recovery. Results show that the water content in the well of CPI water control is only 10% to 33% of the adjacent wells at the same geological layers. The initial oil water ratio in the CPI well is 13, which is ten times better than the adjacent wells. After 2 months' production, the water content of CPI well is 13.3%, compared to 67%, 62%, and 89% of the adjacent wells.