TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractSand production is a major problem in the oil and gas industry. Loss of production, sand disposal issues, the need for routine cleanouts, damage to well jewelry, and stuck well accessories are the most common reasons for setbacks caused by sand production. The sand control methods yield the most desirable results when are implemented early in the life of a well before sand production becomes a problem because of the onset of water production or before formation damage occurs as a result of formation disturbances or subsidence. For the wells that start sand production at a later stage, workover with conventional gravel packing is one way to alleviate the problem, but such a costly undertaking is not always economically justifiable.The candidate field is located at offshore Terengganu in Malaysia and has been in production since 1982. The reservoir consists of several layers, including the unconsolidated (J-sand) layer. Well A, for which the initial producing intervals were isolated, was recompleted in the J-sand layer by March 2005 and started producing 250 BOPD. Unfortunately, the well could only produce for 3 months before it was shut-in due to severe sand production. The well had been shut in for 4 years and even after a series of coiled tubing operations to perform sand cleanout, it was not possible to flow the well for a single day.Because of the marginal reserves available and the high cost of mobilizing a workover rig to perform a conventional gravelpack completion, the operator chose to recomplete the well using a rigless technique that allowed the gravel pack to be placed through the existing completion tubing.To ensure the best possible perforation packing efficiency and annulus pack quality, the "vent screen and isolation packer" through-tubing gravel pack (TTGP) technique was used. After the TTGP operation, production stabilized at about 180 BOPD. This method can be considered for the wells that are shut-in because of severe sand production and the wells that are producing at restricted production rates due to sanding problems.

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Kikeh Field is a deepwater project located in Malaysia. The development plan for this field requires fifteen water injectors, eighteen producers, and one gas injector to be completed in more than 4,300 ft of water depth. In order to maintain the oil production target for this field, the water injection rate should double the target oil rate. To achieve this, water must be injected into the formation at fracturing pressures.The completion campaign started with three water injector wells. The initial results were not as expected, i.e. after pumping 1000 bbls of treated seawater at rates from 7 to 14.5 bpm, surface pressures were still within the pressure limit of 3000 psi, given by the Floating Production Storage and Offloading (FPSO) facilities. However, the injection rate was decreased with increase in pressure, and skin factor was found to be increased. Another observation was that the formation was not fractured at pressures exceeding the expected closure stress.Possible explanations for such behaviour were: (1) the development of a "temperature" sensitive emulsion in the reservoir matrix, (2) the effect of temperature in viscosity of our seawater crude, (3) near wellbore damage caused by fines from the injected water blocking the near wellbore region.When a second injectivity test on the second well was conducted, again the injected rate was not able to create fracture even though the injected pressure was above the breakdown pressure. After analyzing the injectivity data, another mechanism related to poroelastic stress was postulated. Poroelastic stress is a transient localized stress increase caused by fluid injection into porous media.Possible explanations have been looked in details using pressure transient data and it supports the theory of poroelastic effect. Then the remedial action was selected to overcome poroelastic behaviour in the Kikeh field. The operation procedure and the result obtained after injecting Viscoelastic fluids at fracturing rates are discussed in this paper. This paper also describes the evaluation of skin after each injectivity test from pressure transient analysis.

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