BP's down hole instrumentation of the Khazzan tight gas appraisal wells provides a rare opportunity to quantify reservoir pressure and temperature dynamics. Several appraisal wells were initially tested for 3-4 weeks and subsequently shut-in for about a year. The continuous downhole gauge recordings of the resulting pressure build ups were then analyzed to quantify understanding of stimulation effectiveness, reservoir quality away from the wellbore, total producible connected gas, geomechanics and wellbore hydraulics. History matching of this gauge data provided confidence in predicting production profiles for full field development. This paper examines the pressure transient analysis (PTA) of one representative well in the field. The high quality build-up indicated that good quality rock extends to beyond the radius of investigation of the pressure transient and PTA did not reveal any barriers in an area of ~20 sq. km around the wellbore. The absence of boundaries and the possible extension of better quality reservoir have given BP the confidence to place an additional (and successful) appraisal well in the southwest of the block, thus extending the area that potentially will be a focus for early full field development. Installing permanent down hole gauges carried a high initial cost, but the value gained in quantifying subsurface uncertainty has proven the success of this technology application. It has also proved invaluable in executing hydraulic fracture stimulation. This high quality information boosts confidence in reservoir performance and long term deliverability leading to better informed business decisions regarding potential full field development. Value of Tight Gas Well TestingThe majority of tight gas wells require hydraulic fracturing to make them flow commercially. This process involves physical disturbance to the near-wellbore region that can extends a few hundred feet inside the reservoir. The shape of the propped fractures is still a subject of big debate in the tight-gas industry. Although many post-frac tests show linear-flow regime, this does not warranty the linearity of the fracture shape inside the matrix. Well tests are based on average theory and only give flow-related (effective) average numbers without giving any indication of shape or direction. Other datasets are required to support the conclusions of well-test results. This can be geological data to support interpreted geological features, near wellbore damage data to support skin damage, interference tests to support permeability interpretations, or more exotic data like microseismic to support propped fractures length and vertical extension. Interpreted well-test data are very critical in driving large projects. Fracture length is very important in driving well initial deliverability. Many tight-gas projects rely heavily upon this high-rate fracture dominated deliverability to support their development. Therefore, it is vital that great care is taken in addressing the uncertainties associated with the interpreted data, especiall...

Available headroom (difference between dewpoint and reservoir pressure) in liquid rich gas reservoirs and drawdown scenario affect the condensate dropout near the wellbore. Although effects of the liquid dropout are well understood in radial system, addition of hydraulic fracture in the low perm reservoirs complicates the saturation profile in reservoirs. Massive hydraulic fracturing in vertical tight sand wells adds effective surface area to flow and can mathematically be considered as placing long horizontal wells to reduce overall well draw downs. This work shows that this additional contact with matrix rock, therefore, can play a major impact in mitigating or postponing the impact of skin caused by condensate banking. This paper presents a real case of Pressure Transient Analysis (PTA) for hydraulically fractured wells in unconventional gas-condensate reservoirs. Detailed analysis of PTA will be discussed and addressed using analytical and high-resolution numerical models in which compositional multi-phase flow is considered. The numerical model is history matched and fine-tuned on pre-frac and post-frac well test results. The impact of hydraulic fracture half-length, fracture conductivity and matrix relative permeability on condensate banking effects will be addressed via a numerical simulation study for various scenarios. The paper will demonstrate the value of hydraulic fracturing in reducing condensate baking effect on well productivity and, by inference, the impact on the long-term economic value of gas-condensate wells.

BP is developing the Khazzan and Ghazeer fields of Block 61 in the Sultanate of Oman. The development includes three Cambro-Ordovician tight gas sand reservoirs which require hydraulic fracturing for commercial production rates. There are challenges with depth and high temperature for the open hole logging environment, with a restrictive inner diameter and residual proppant creating challenges for the cased hole logging environment. Additionally, there are cost challenges on all data acquisition including coring, downhole gauges, sampling, proppant tracers and many other forms of surveillance. This paper outlines the evolution of the data acquisition strategy for the Khazzan and Ghazeer assets. The development plan at project sanction was 20 vertical and 272 horizontal wells. The data acquisition strategy led to the development of a data acquisition plan, and all stakeholders were engaged to ensure the right data was acquired in the right place at the right time. Cross functional behaviours and fiscal discipline were essential in this process. Inclusion of the service companies into the wider BP team was crucial to ensure appropriate technology was applied, learning from previous operations implemented and new technology options made available. Through careful management of the data acquisition plan, all data in development wells prior to first gas were acquired within the allocated data acquisition budget despite drilling 20% more wells than originally planned for this period. Early improvement in subsurface understanding enabled an overall reduction in well count for the life of the project, extension of the original development into unpenetrated areas, adding significant value to the project.

The Amin formation is a tight sandstone formation, that is present in Block 61 in the Sultanate of Oman, that has presented a number of development challenges. The Amin reservoir is characterized by an average permeability approximately two orders of magnitude lower than the Barik formations, which is the other main current development reservoir within the field. Adding to the challenge is the presence of the immediately and extensively underlying Buah formation, which is known to be sour. During the Appraisal phase of the project, two vertical wells and one horizontal well were completed in the Amin, demonstrating that a horizontal well profile with multi-stage fracturing would most likely be required to achieve consistently commercial rates. It was also evident, even during the project sanction, that significant further investigation would be required to be able to more completely understand the hydraulic fracture behaviour in the Amin; in terms of the created fracture geometry, appropriate hydraulic fracturing methodology, suitable formation connection techniques, and other completion design factors to succeed with a reservoir development. Additionally, it was known that understanding reservoir fluid distribution would be fundamental to delivering such wells. During the Development phase several vertical wells were completed with a range of fracture types and designs, to facilitate an assessment of well performance in the vertical geometry, as well as understand the fracture height for various hydraulic fracturing techniques, including High Rate Water Fracturing (HRWF) treatments as well as Hybrid-Frac (HF) type approaches. Additionally, several horizontal wells were also completed to build upon the Basis of Design (BoD) that had been selected at the end of the Appraise phase, with a continuous learning approach taken to further develop the frac understanding. Lessons more recently learned from North American unconventional reservoir stimulations were also investigated, carefully selected and then subsequently applied in a coherent and systematic way. This paper presents a review of several of these vertical wells and two horizontal wells, attempting to demonstrate the progress made between the approaches. Additionally, the two horizontal wells will be used as a case study to illustrate the application of the continuous improvement methods, as well as the adoption of some key appropriate technologies transferred from North American unconventional reservoir stimulation approaches. These included an investigation of perforation cluster efficiency, the baseline fracture design and fracturing fluid types; as well as integrating directly with the open-hole characterization and production logs to enhance the frac designs and results.