A deployment system has been developed which allows for the insertion of any length of Bottom Hole Assembly (BHA) both into and out of wells, under pressure. Simultaneously a Down Hole Swab Valve (DHSV) has been developed which also permits the insertion of long BHAs into live wells. These developments mean that the lubricator height is no longer the limiting factor for the length of a BHA. These techniques can be applied to:–Long perforating guns–Long logging tools–Running screens or other completion components into live wells The deployment system has been used in the field to run 910 ft of 2-7/8" perforating guns into a horizontal well in the Dutch sector of the North Sea. The first use of the DHSV is anticipated in a multilateral well in the Danish sector of the North Sea. The debut for both systems was intended for perforating a well in the British sector of the North Sea. This paper explains the process of evaluation, selection, development and testing of both systems. The relative applicability of each system is discussed. Introduction The normal constraint on the length of BHA which can be run in a live well is the distance between the top of the lubricator and the swab valve of the Christmas tree. Occasionally extremely long BHAs are called for, or headroom limitations severely restrict lubricator height and so various techniques are been used to circumvent this constraint on BHA length, each with particular limitations. Lubricator Valves. These are working valves in the production string. The lubricator valve is controlled by annular pressure. They are only used for drill stem tests and are not suitable for production wells. Subsea BOP or Christmas Tree. When working on a subsea well a far greater length of riser is available. However this is obviously not an option for platform or land wells. Well Kill. If neither a lubricator valve nor a subsea BOP is applicable, and the BHA cannot be reduced any further by carrying out multiple runs, then a well kill is required. Once a well has been killed then any length of BHA can be inserted. However killing a well is a lengthy and expensive operation, reservoir damage can result, production can be difficult to reinstate, and it may not be desirable to carry out operations such as logging or perforating with kill fluid in the well. In 1994 Shell U.K. Exploration and Production identified a requirement to perforate a platform well over a number of sections of a 300m interval. On this occasion it was preferable to perforate the entire interval in one run, whilst underbalanced. Because the well was inclined at 800 completion conveyed guns could not be dropped into the sump. This relatively unusual perforation requirement was studied in some detail and the new technologies of Deployment Systems and Down Hole Swab Valves identified as being the most appropriate method of running the coil tubing conveyed perforating guns. The first subject this paper addresses is the process by which this conclusion was reached. This was to have been the first occasion on which a Deployment System was used in the field and so a comprehensive series of trials, Failure Mode And Effect Analysis (FMEA), and Hazard And Operability (HAZOP) studies were performed. This paper reviews the results of these trials and studies. The desirability of incorporating a Down Hole Swab Valve was identified early on and appropriate specifications developed. At the time no suitable product existed and so Baker Oil Tools designed, manufactured and tested a suitable product. Consideration of Alternative Perforating Options. Initially a number of perforating options were screened:Multiple runs using electric line.Completion conveyed guns dropped into a rathole.Drillpipe conveyed guns retrieved to surface, followed by well kill and completion running.Multiple runs using coil tubing conveyed guns.Single run using coil tubing conveyed guns and deployment system. Conventional multiple electric line runs were rejected on technical grounds because of the high deviation. P. 415

Several recently introduced oilfield perforators incorporate reactive materials that are derivatives of military-based weapons technology. Claims have been made that reactive shaped charges provide improved downhole performance and well productivity over conventional shaped charges by creating optimized perforation tunnels. To better understand and quantify differences in penetration and flow performance between reactive shaped charges and conventional shaped charges, we designed a test matrix that takes into account various environments, such as gas in low permeability rock and oil in higher permeability rock. The performance assessments of reactive vs. nonreactive perforators were performed under controlled conditions in an API Perforation Flow Laboratory (PFL) (API 2006). The tests, which involved shooting into stressed rock under simulated downhole conditions, were conducted in Berea Sandstone targets with mineral oil flow to simulate a typical oil-bearing formation, and in Carbon Tan Sandstone with nitrogen flow to simulate a typical gas-bearing formation. The Berea Sandstone represented moderate-to-high porosity and permeability rocks with high, unconfined compressive strength (UCS). The Carbon Tan Sandstone represented low-permeability and medium-porosity rocks with moderate UCS. To further understand the contribution of the reactive component, tests were performed in balanced, underbalanced, and overbalanced conditions. Charge performance measurements were taken for both conventional and reactive charges in each target reservoir rock. This paper describes the methodology used for the comparative tests between reactive and nonreactive perforators in the Berea Sandstone portion of the program and summarizes the observations of core penetration, clean up, and productivity. Introduction The API Recommended Practices for evaluating well perforators (API 2006) provides an essential protocol for measuring and quantifying the effects of changes to shaped-charge perforators designed for increasing penetration and flow performance. Laboratory simulation of a downhole perforating event involves detonating a single shaped charge into a stressed porous media using a hardware configuration that is similar or equivalent to that used in the wellbore. In this study, three different reactive charges and one conventional charge, all under the sub-grouping of deep penetrators (DP), were shot into two sets of downhole-configured targets, and the penetration and flow performance were compared. Three borehole conditions were simulated for each of the four charges: underbalance, balance, and overbalance. For statistical validity and verification, the test for each borehole condition was repeated three times and independently witnessed, resulting in a total of 72 tests. To replicate downhole perforating conditions, the setup consisted of commercially available 3-3/8-in. deep-penetrating shaped charges (listed in Table 1) that were shot from inside a pressurized wellbore using a simulated single-shot perforating gun, through a simulated scallop, fluid gap, casing plate, cement sheath, and into the formation-analog rock. Phase I used a stressed Berea Sandstone core filled with odorless mineral spirits (OMS), and Phase II used a stressed Carbon Tan Sandstone filled with nitrogen (Table 2). The acquired data include, but are not limited to, depth of open perforation tunnel, depth of total perforation penetration, the perforation geometry, hole diameter in casing and cement, flow performance, flash radiography images, and time vs. pressure traces (Appendix A), as well as statistics on significance (Appendix B), CT scans (Appendix C), and thin sections of the perforation tunnel walls (Appendix D).