Summary This paper describes the technical basis for the design and implementation of a coiled-tubing (CT) underbalanced drilling (UBD) campaign in the Sajaa field in Sharjah, UAE. The campaign calls for up to three multilaterals per well to be drilled underbalanced from the existing wells' through tubing. The paper describes the analysis, modeling, and result, and their implication in the selection of the operational approach. The key issues associated with the campaign, many of which were unique and challenging within the context of UBD, are discussed, with specific reference to the Sajaa-3 well, which was the first candidate. These includeTemperature modeling and thermal considerations because of the high bottomhole temperature (BHT).Compositional pressure/volume/temperature (PVT) behavior of the produced fluid.Feasibility, underbalanced operability, and controllability of through-tubing UBD operations.Risk to underbalance from near-wellbore depletion of the reservoir caused by long-term production from the motherbore.Estimation and impact of the productivity of the motherbore and open laterals while drilling subsequent laterals.Risk from reservoir parameter uncertainties.Hole-cleaning risks.Designing for zero flare.Consideration of mechanical and hydraulic limitations to the drillable lengths.Equipment limitations. The paper details the analysis approach used, assumptions made, models used, and the results. It should be noted that the Sajaa produced fluid is a retrograde condensate and the inflow performance was nonlinear and, therefore, consideration of these in the basis of design (BOD) becomes critical. The goal of this work was not only to create the technical BOD for the well, Sajaa-3, but also to set the parametric limitations for a wide range of well types that were likely to be encountered in the continuation of the campaign. On the basis of this work, an approach to drilling and monitoring the well to minimize the risks was developed, and it formed the basis of the drilling operation. The ongoing campaign, now well past 30 wells, has been one of the most successful applications of CT UBD. The results of the drilling operation of Sajaa-3 and the subsequent wells and their implications to the design basis are also discussed.

This is the second half in a two part series on the Sharjah Sajaa gas field repairs. The Sajaa gas condensate field is located onshore in the Emirates of Sharjah UAE. It is producing out of the Thamama limestone reservoir between 11,000 (3,350 meters) and 13,000 (3,960 meters) feet true vertical depth. Reservoir pressure is declining thus creating greater demands on the production strings to prevent collapse from overlying sediments. Sajaa field has had a history of collapsed casing on wells Sajaa 33 and 39 (twice in the same well). In order to investigate the cause of collapse and to prevent further collapse a Peer Assist (Group Meeting) was held in Sharjah to discuss the wells histories and develop a plan forward. Paper One will discuss the CWEAR, READ, casing calculations, the decision tree and well selection. This paper will discuss the live well workover program. Background and Technical Need It was initially proposed that some of the Sajaa wells were tubing constrained from a gas production point of view, i.e. the small 5-inch (127 mm) tubing was causing additional pressure drop which limited production. At the same time, it was found that Sajaa 33 had collapsed. Additional study had found that Sajaa 39 had collapsed twice while drilling but the cause was unidentified. Further investigations showed that 10 other Sajaa Wells (Numbers 29,32,33,34,35,36,37,38,39 and 40) could have had severe drill pipe hard banding induced wear through critical directional doglegs in the 9–5/8 inch (244 mm) casing tortuosity while drilling the laterals and multi laterals and thus this could be the principal cause of the collapse on Sajaa 33 and Sajaa 39. Computer based wear prediction tools (C WEAR) which required bottomhole assembly description, drilling times, directional surveys, mud weights, pore pressure estimates, formation tops, weight on bit and rpm where given to the BP Upstream Technology Group in Houston to develop predicted wear patterns and areas of concern in the aforementioned wells. Multi-finger callipers were run to analyse the wear and predict the collapse and burst value of the remaining casing wall. The study confirmed as much as 30 to 40% of wall loss was predicted and measured by the READ callipers in high dogleg areas thus reducing the ability of the pipe for collapse strength. Several solutions were considered including conventional scab liner or an expandable tubular technology where then reviewed as a solution to strengthen the existing 9–5/8 (244 mm) casing; however the prototype expandables could not meet the timeline and therefore the scab liners where adopted for the project. All operations were performed with a Hydraulic Well Control 460 snubbing unit under live well conditions (the wells where not killed). Well productivity after the hydraulic restriction was removed was 35%, which was higher than predicted and the operations where completed on 6 wells in 208 days.

No abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Sajaa gas/condensate field is located onshore in the Emirate of Sharjah UAE. Production is from the Thamama limestone reservoir at 11-13,000 ft. TVD. Reservoir pressure depletion is creating an ever increasing collapse pressure differential on casing opposite overlying sediments.Sajaa field has a history of collapsed casing on wells Sajaa 33 and 39, with two collapse events in the latter wellbore. The current study summarizes the theoretical effort to prevent collapse in the remaining Sajaa wells. A companion paper 1 discusses the related live well workover program.Current Sajaa completions are packerless, producing up the tubing or up the annulus between the production casing and a capillary string for corrosion inhibition. Coincidentally, the collapse resistance of the production casing is reduced by severe wear associated with the use of tungsten carbide hard banding while drilling the reservoir sections of the wellbore.Setting the context for the study, the well(s) tubular program, pore and internal pressures, and design safety factors are presented. This introductory portion also clarifies the differential collapse load to which the tubulars are subjected.Loss of collapse resistance due to severe wear is then addressed. The theory of wear prediction is reviewed, and then demonstrated, as the drilling parameters of several of the affected wells are used to predict their current state. These predictions are then compared to mechanical caliper measurements taken during intervention and repair. Further, using specially machined wear grooves, the effect of wear on collapse of a casing cross section is experimentally validated by full scale collapse tests.Results of both the wear prediction/measurement and its effect of collapse resistance are input to a probabilistic decision tree to tailor each well's workover strategy. The decision tree permits risk-weighting of alternate strategies for repairing the Sajaa casing. An important component of the decision tree is the consideration for time varying alteration of the collapse differential pressure with reservoir depletion.

Overview A Dynamic Freeze Plug Process (DFPP, U.S Patent 5,649,594 Flak, L.H) was applied to several packerless Sajaa Field wells to achieve a second mechanical annular pressure barrier prior to removing the trees for hydraulic, live well work over operations. Four wells were successfully frozen with minimal fluid lost to the formation. Several equipment and procedural modifications made after the first job improved subsequent jobs and reduced the time required to complete the freeze and achieve barrier. The DFPP is a proven technique to achieve an annulus barrier in a gas filled environment. Background and Technical Need BP's Drilling and Well Operations Policy requires two independent pressure barriers before any pressure envelope is broken for well interventions. The barriers must be capable of operating independently and simultaneously and must be pressure tested from the direction of flow. Dual tubing barriers are easily achievable with tubing plugs, tubing hanger backpressure valves, or a combination of the tow. The packerless wells in Sajaa Field only have one permanent annular barrier, the metal-to- metal tubing hanger seal, and during normal well operations the annulus is pressured at the surface. Thus, achieving additional annular barriers is more challenging, Sajaa well completions consist of tubing strings landed above the perforations or horizontal lateral zones, or tubing strings set in permanent packers to separate multi-lateral zones (Figures 1a. and 1b.) Several service company barrier proposals involving various kill fluids an/or inflatable tools deployed on coilded tubing were reviewed. Due to the depleted state of Sajaa's fractured carbonate reservoir, kill fluids of any type were undesirable due to the risk of permanent and irreversible formation damage. Inflatable tools alone were thought to be too unreliable to depend upon as a second barrier, especially in the multi-lateral wells where an inflatable would have to be set in open hole. Additionally, inflatable would have required kill fluid to be placed on top of them to balance the formation pressure. This kill fluid would be difficult to remove, and some would likely be lost to the formation upon removal of the tools. If lost in the hole, the inflatable themselves might have caused irreparable lost production. Freezing the spool was discussed but thought to be impossible because the wells would not hold static fluid column to surface1–2. Boots and Coots International Well control proposed the DFPP as a potential solution. They developed the technique for a South American client in 1995 and patented the process, but prior to the Sajaa work the process had never been performed in the field. The process seemed ideal for this application: creation of an second independent annular barrier capable of being tested from the direction of flow, applied near the surface of the well, with minimal fluid loss to the formation.