In the last decade, hydrocarbon production from low-permeability reservoirs has been on the rise. Multi-stage hydraulic fracturing is the most common technology used to make production from such reservoirs economically viable. Radioactive-tracers and production logging, which are usually used to assess fracture flow efficiency, do not always provide reliable information in terms of the fracture effectiveness and total frac flow height. An advanced technique described in this paper not only can identify active fractured intervals but also quantify the inflow profile. A novel technique was developed to locate fracture inflows and quantify inflow profiles in hydraulically fractured wells. It builds on the industry-proven combination of Spectral Noise Logging and High Precision Temperature Logging. This technology was initially implemented for qualitative and quantitative analysis of reservoir flows, including those through leak points, cement, reservoir rock matrix and reservoir fractures. Fracture flow intervals are located using a new-generation of Spectral Noise Logging tool with wider dynamic and frequency ranges. Quantitative inflow profiles are derived by temperature modelling. The technology described in this paper allowed assessment of hydraulic fracturing effectiveness in the producing wells of Petroleum Development Oman. Three case studies are presented to demonstrate the application of this technology in two producing gas-condensate wells and one oil well, one vertical gas producer and the other horizontal, drilled into clastic low-permeability heterogeneous layer-cake reservoirs and therefore requiring multistage hydrofracturing for commercial hydrocarbon production. Production profiles were determined for all wells, with inflow splits between producing zones quantitatively analysed using temperature modelling, matching the recorded and modelled temperatures, pressures and phase compositions, and taking into account surface data, such as production history and separator test data, and PVT fluid properties. Spectral Noise Logging was used to determine the frac flow intervals. In the vertical well, the survey was conducted at three different flow rates to improve inflow quantification by matching three data sets. The survey results were used to successfully evaluate the effectiveness of multi-stage hydraulic fracturing and fracture height. The acquired information was used to improve hydraulic fracturing planning and design for the field. One of the advantages of applying this technique for fracture flow evaluation is its ability to survey wells under existing operating conditions without shut-in and production deferment. As opposed to conventional production log with spinner, described technique can locate and quantify flow behind pipe.

A recent series of tight gas discoveries in the Amin format ion of the greater Fahud area represents some of the most exciting exploration success of this decade in the Sultanate of Oman. The structures have been evaluated as containing very significant amounts of gas locked in a challenging deep and hot environment requiring hydraulic fracture stimulation. Recently, horizontal well trials started taking place in two of the structures aiming for testing efficiency of this type of completion and further evaluation of formation deliverability. Successful completion of horizontal laterals would open new horizons in this challenging environment. Achieving this goal is not possible without thorough evaluation of reservoir conditions followed by completion and stimulation. Horizontal well performance in a tight gas reservoir is largely controlled by the number of hydraulic fractures placed along the lateral and their spacing and conductivity. Designing a reservoir access strategy might not be a trivial task, either, when the well trajectory intersects several productive vertical layers and the reservoir properties are changing laterally. Manual selection of intervals and perforations could be susceptible to mistakes and may be perceived as subjective at times, while also being time and effort consuming. The workflow based on reservoir quality (RQ) and completion quality (CQ) developed in North America for unconventional resources for optimizing completion decisions brings engineering to this process for stage and cluster selection in horizontal sections. This project applies the same reservoir-centric RQ/CQ workflow integrating all available data and creating specific criteria and cutoffs applicable to a specific tight gas field in the Sultanate of Oman.

In 2009 Petroleum Development Oman LLC (PDO) started an ambitious tight and deep gas exploration programme, exploring for previously untapped reservoirs, both conventional tight gas plays as well as deep unconventional gas resources. These resources are typically in previously undrilled formations at great depths, highly overpressurized with high temperatures, and uncertain fluid fill and composition. The unique geological properties of this type of reservoir require different strategies and technology deployment in order to make them viable and sustainable (Briner et al., 2012). With unique geomechanical, reservoir, and geological properties, some of the large gas-bearing prospects within the Fahud Basin such as the Khulud exploration area require innovative and complex drilling, completion and fracturing practices. A revised hydraulic fracturing execution workflow, with specific technology application, has been developed in order to account for such geological and reservoir complexity. Because of the uniqueness of the structure in terms of depth, temperature, reservoir pressure and stresses, different strategies should be used for successful hydraulic fracturing. This paper demonstrates the changes to the original understanding of fracturing processes and execution in order to achieve successful fracturing implementation, production testing and reservoir evaluation. Six main aspects are covered, these are as follows: abrasive jetting perforations as a standard application, fracturing fluid optimization in HPHT environment, modified fluid design, stair-step ramping of the pumping schedule, engineered fracture design to achieve sufficient fracture length and conductivity and post-frac flow-back monitoring and assessment.

South Oman contains several tight silicilyte reservoirs with significant locked hydrocarbon volumes. Successful hydraulic fracturing is key for unlocking commercial production. Low production rates coupled with fast declines have remained a challenge and a new economically attractive development scheme was required. Through integrated re-evaluation of the geology and reservoir, a modified frac approach was designed to create more connectivity to the reservoir height, using an unconventional frac design and frac fluids plus over-flush. Poor well productivity in tight silicilyte reservoir can be explained by low permeability of 0.001-0.1 mD and laminated texture with almost zero vertical permeability. Fit for purpose modelling was performed to assess the forecasting range for sub-surface uncertainties and frac parameters. One of the key changes for a successful development strategy was to place a higher number of fracs to overcome the extreme lamination. [1] It was observed that the "conventional" fracturing approach inaccurately assumed higher vertical fracture coverage of the reservoir and that the guar fluid used was much more damaging due to low recovery after frac clean-up. Fifteen unconventional fracs were pumped successfully with over-flush pumping technique. To understand if this new unconventional approach was effective in overcoming the extreme lamination required additional understanding of fractures geometry and orientation. To confirm fracture dimensions and flowing heights; a set of radioactive, chemical tracers and logging activities were completed. Flowback results showed that the unconventional frac [3] fluid used, was relatively easy to recover from formation and better cleaning-up of fractures can be achieved. This led to successful well clean-up compared to previous wells in the same field and confirmed better fracs clean up. Initial production results confirmed at least double well initial productivity, which should lead to better stable oil production from the field. Radioactive tracers logging, Sonic logging and Spectrum Noise Logging (SNL) confirmed mechanical and conductive fracture heights. Sonic logging also confirmed frac orientation. Oil and water dissolvable tracers confirmed fractures clean up from water and oil production intervals. Full geological and reservoir understanding, out of box thinking in frac technology allowed the asset team to come up with an unconventional development approach to improve commercial production from tight silicilyte reservoirs. The new frac approach included unconventional frac design and fluids, and execution using over flush and resulted into unlocking significant reserves. A more economic full field development is being planned and replication of the new frac approach is already ongoing in other fields.

There have been many oil and gas field discoveries in the Cambrian Ara Group intra-salt carbonate rocks in the South Oman Salt Basin. These carbonates represent self-charging petroleum system with over-pressured hydrocarbon accumulation in dolomitized rock encased in the salt. Drilling and completion wells going through salt is challenging. Salt creeping behavior results in issues of stuck pipe during drilling operations, casings deformation and collapse that have led to well suspension and abandonment. The full set of the available historical data analyzed to identify magnitude and history of the problem. The study conducted to estimate of salt creep magnitude, to assess the effect of the salt creep on cement quality, drilling and completion risks. The risk of salt creep on the drilling, completion and long-term well integrity was evaluated with multi-disciplinary integration of geological, geomechanical, petrophysical and well engineering aspects to minimize and mitigate the salt creeping risks. In addition to identify root cause for completion failure and providing recommendations to drilling practices, cementation and completion design that can improve well delivery process. Salt creep behavior presents drilling challenges associated with excessive torque, stuck pipe, casing deformation, and poor cementing job. Salt creep associated risks to drilling and well integrity should be managed and mitigated. Key study findings captured for wells designs were: Salt creep rate increases with depth, salt thickness and differential stress (function of MW)Non uniform loading decreases the collapse rating of the casing and results in casing deformationNon-uniform loading likely due to poor cementing, interface between rigid carbonate intervals and salt, and irregular open hole quality. Studied casing collapse cases could likely be attributed to several factors or combinations of factors such as salt mobility behavior, drilling with low MW, poor cement jobs and loss of internal hydrostatic support for the casing after cement job between liners lap. The improved multi-disciplinary understanding of salt creep is vital to reduce drilling and completion costs, unnecessary well abandonment and achieve good life cycle well integrity i.e. avoid extra side-track and workover cost due to integrity issues. The best practices and conclusions summarized in the study for drilling and completion design expected to benefit the exploration and development projects for the salt encased carbonate reservoirs around the globe.