Horizontal screen failures can be serious, resulting in expensive remedial operations including early abandonment, in the extreme case. Globally, screen failures in horizontal wells completed in loose unconsolidated sandstone reservoirs have become common. Consequently, from completion and longevity perspectives, a high percentage of horizontal wells have not achieved the desired result: sand-free, high sustained-productivity producers. Individual companies have performed studies in this direction, and some are still ongoing. From preliminary data available, however, it has been possible to observe trends and determine the failure mechanisms. Failure categories highlighted in this paper include wells with significant impaired productions or those completely plugged, representing an overall failure rate of almost 20%. This paper suggests several levels of screen failure: screen collapse or complete plugging, partially plugged screens (poor performing wells) and those producing unacceptable amounts of sand. Other failures include improper installation and economic failures where fixing the problem is possible but costly. Some wells exhibited "early mortality " producing sand at production onset. The study further categorized possible causes of screen failures into three major areas:Screen plugging caused by high-pressure drops across screens, hot spots of localized production, fines and dirty sand.Incorrect procedures, materials or equipment selection including trouble installing the screens, corrosion in low spots due to standing acid, generalized corrosion from acids, improper cleanup, ineffective mud removal, ineffective sand control, inappropriate screen selection and erosion.Poor reservoir understanding in the areas of grain size distribution, sanding up due to water production, open annular areas due to higher than expected rock strength. This paper reviews various applications of soft rock completions in horizontal service, along with benefits and shortfalls. The performance characteristics of the various screens relative to each other from the perspective of flow capacity, plugging and erosion resistance are examined. Recommendations based on "best practices " being adopted to combat screen failure problems in high permeability reservoirs are also showcased. Introduction Screens deployed in horizontal wells provide means of sand control for most of horizontal reservoirs.Horizontal screen failures can be serious, resulting in expensive remedial operations including early abandonment, in the extreme case. A typical screen failure manifests as an opening in the screen that is larger than the design value, permitting large particles from the formation to pass through them. The consequence is excessive sand production and loading of the bore hole with sand and eventually cutting off production (Fig. 4,5 & 6). High costs of separation, treatment and disposal could then make the well economics unfavorable. Apart from the economic impact, safety and environmental concerns (sand disposal) are becoming more critical as sand production increases. It is therefore in order to study various screen failures and make recommendations based on "best practices ' ' that have been adopted to combat screen failure problems in high permeability reservoirs. Various designs of screens have been employed in wells for sand control in unconsolidated high permeability sandstone reservoirs. Commonly used screen types are wire wrap screens, slotted liners, pre-packed screens and premium screens like the Excluders or Strata Pac.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHorizontal screen failures can be serious, resulting in expensive remedial operations including early abandonment, in the extreme case.

Identifying suitable kill fluids to temporarily control prolific oil and gas reservoirs without risk of formation damage has been a challenge within the Niger Delta. Various attempts, particularly in gas wells using conventional brines and gels to enhance well intervention processes normally require stimulation treatments, in order to bring the wells back to production. The engineered cross-linked gel is a temporary blocking formulation used to protect permeable zones from invasion of fluids. This system contains a low-residue cellulose-polymer with a cross-linking agent and can be designed for use with an internal or external breaker. In general, the use of loss circulation material (LCM) is not recommended because of its tendency to block perforations, complicate fishing operations and increase the difficulty of clean-up if fishing becomes unsuccessful. This case study is of a gas well drilled and completed for an Operator on the E4.2-reservoir with production capability estimated at 8,000 bbl/day of condensate and 150 mmscf/day of gas. Following the installation of the memory gauges, a 10-hour build-up test of this particular interval was conducted. During the retrieval of the BHP gauges, several incidents lead to three successive fishes getting stucked into the wellbore. The Operator was faced with many challenges: ‘do nothing and produce the well in an unsafe manner at 50% potential’, ‘attempt a workover’ or ‘attempt a coiled tubing rigless intervention’, with each option having its attendant limitations. The success in retrieving the multiple fishes was attributed to the ability to kill the high pressure gas well with a time dependent and acid degradable cross-linked gel system through a high rate bullhead pumping technique. The gel had low damage potential to the formation and prevented the migration and fingering of formation gas to the surface throughout the fishing operation that lasted for approximately one month on 24-hour daily operations. The pre-fishing conduit potential was preserved, indicating that the cross-linked gel completely got degraded internally at the end of the fishing operation leaving the near wellbore region undamaged. In this paper, the laboratory simulation, features, engineering design, field application and benefits of the engineered cross-linked gel system are discussed. In addition, the process of well killing, specialized coiled tubing and wireline fishing tools and performance evaluation are addressed. The success of the operation includes regain of the original well performance, competence in well killing and complex fishing, cost savings and high NPV. Over $2.0 million was saved operationally with the CT rigless activity when compared to ‘workover’ or ‘do nothing’ options. Background / Problem Statement The case study was the first of 16 drainage points planned to be drilled and completed for the supply of gas to the NLNG project from 1999. The well was drilled & completed on the E4.2 reservoir with a single 7″ × 5-½″ 13 chrome tubular completion. Following successful installation of the memory gauges and production well test, the well was closed in for a 10-hour build up. During retrieval of the BHP gauges the 0.125″ wireline broke at surface and fell back down the well. Attempts were made to cut the 0.125" wireline in the hole by using a blind box run on a second 0.108" wireline and toolstring. However, during the jarring process, the toolstring on the 0.108" wireline got entangled around the 0.125" wire in the hole and became stuck around the original fish at a depth of 11,762 ft. A centralised Go-Devil, followed by a cutting bar was dropped in an effort to recover the 0.108″ wireline, but the 0.108" wire was cut prematurely at around 627 ft, leaving both the memory guages, 0.125" and 0.108" wires in the well. A wire finder tool was run and confirmed that the Tr-ScSSSV was clear of wire, as the top of the wire was located at 586 ft.

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