fax 01-972-952-9435. AbstractUnderbalanced drilling (UBD) technology has been gaining in popularity around the world because of its capability to reduce or eliminate formation damage, to increase production rates, and in some cases, increase the volume of recoverable reserves. The technology is applicable to fields where formation damage is a concern or where problems such as severe fluid loss, differential sticking, steering problems or slow drilling rates are encountered with conventional drilling.With underbalanced drilling, the formation pressure is greater than the hydrostatic pressure, allowing hydrocarbons to flow into the wellbore during drilling. This prevents potentially damaging drilling fluids and drilled fines from penetrating the producing formation.In previous experiences in the field using traditional drilling methods, considerable formation damage had been experienced, and although UBD had never been attempted in the area before, Brunei Shell Petroleum and its government partner decided to use this technology in a three-well trial in the Rasau field, located onshore in Kuala Belait, Brunei.Of the three wells attempted during this UBD trial one well could not be drilled due to catastrophic borehole collapse. The other two wells were successfully drilled to depth using UBD techniques; however, multiple hole volumes of solids were produced during drilling and production testing, indicating borehole stability problems.Production rates observed after drilling to TD and prior to running completions indicated zero formation impairment, with well productivity exceeding expectation; however, during the completion phase, mechanical problems occurred, and post completion well tests indicated productivity reductions of 60 to 70% compared with the pre-completion tests. This paper discusses the planning, drilling, results, highlights, and lowlights from this UBD trial, along with learnings and recommendations for future application of the technology.The execution of the program led to a sharp learning curve, and the development of recommendations that can be applied to future operations in this field. These primarily relate to well (construction) design, drilling procedures, equipment design, rig-up and rig-down optimization between wells, and completion design.

Sharjah National Oil Corporation (SNOC) currently operates 3 fractured carbonate mature gas-condensate fields with some 35 years of production history. Until recent years these fields were operated by leading International Oil Companies (IOCs) which utilised some of the then latest technologies, such as underbalanced coil tubing drilling in order to maximise the production rate. The reservoir development and management scheme, however, did not involve gas re-injection to maintain reservoir pressure above the dew point. This led to production by simply blowing-down the field. Since there was negligible aquifer support the reservoir pressure declined rapidly and the dew point pressure was reached within 3 years, resulting in condensate drop-out in the reservoir. It is estimated that more than half of the original condensate in place still remains in the reservoir, although more than 97% of the gas in place has already been produced and the reservoir pressure have declined to around 10% of initial pressure. In order to determine the location and quantity of condensate remaining in the field, dual porosity reservoir models were created with legacy data which replicated the naturally fractured reservoir. These models were history matched and gas injection simulation runs were performed in order to estimate the injection rates, reservoir pressure increase, field communication and potential for condensate re-vaporization and mobilisation theory at a variety of pressures. This theory was put to test and confirmed when SNOC recently performed a pilot gas injection project in one of its fields. A mixture of processed gas from the gas plant was injected and allowed to stabilise. The new mixture of injected and reservoir gas was reproduced to estimate the deliverability and ability of dry gas to vaporise the in-situ condensate. A fundamental challenge with SNOC was to determine the PVT property of the initial reservoir fluid from a surface recombined sample which made it extremely difficult to decipher the original fluid properties and history matching the reservoir model. Utilising the field for gas storage can help elevate the reservoir pressure and increase the vaporisation of condensate, however since the field is naturally fractured it is susceptible to the injected gas fingering into a producing well. SNOC now plans to continue the next phase of the project to mature the modelling work, evaluate various sources of injection gas, understand the project uncertainties and establish the conditions required for the ECR project to be economically viable. This paper discusses the challenges, observations and its conclusion through the pilot gas injection project and its impact on the decision making for large scale implementation of enhanced condensate recoveries in the Middle East. Maximizing field development objectives by combining various opportunities is the key to determining sustainability in the lower oil price environment. This paper demonstrates how new technology combined with large volumes of legacy data can provide the perfect platform to evaluate the potential for enhanced condensate recovery (ECR) projects and take informed decisions for operators.