AAPG/EAGE/SPE Shale Gas Workshop

Technology has been developed over that last 20 years focusing on accessing the shale gas and shale oil resources in North America. Many of the same challenges encountered in North America will be encountered during developments of shale gas and shale oil in the MENA region. Additional challenges will also be experienced in MENA which have not been addressed in earlier developments - technically, environmentally, commercially, operationally and politically. This presentation addresses some of the similarities and contrasts which are expected during shale gas exploration and developments in the Middle East compared to North America, building upon earlier publications and presentations.

This poster will present a summary of operations in the USA shale plays showing the range of e-line services performed on tractors. 3 cases will also be presented: 1. Conveying (pulling) a microseismic array for monitoring a fracturing operation 2. Conveying (pushing) logging and perforating services 3. Combining milling and cleaning services

The Natih B formation is a well-known source rock in Oman. On Block 15 in northern Oman it is 25 m thick, has a TOC of ca. 5% and is early mature for gas. Block 15 has a 1,100 m long sidetrack parallel top Natih B within a distance of 15-20 m. It is presently being considered whether this sidetrack should be frack'ed and used to test the shale gas potential of the block.

Shale formations have laminated structures that result in directionally dependent geomechanical properties and anisotropic horizontal stresses. Traditional isotropic stress approaches typically used in pre-drill wellbore stability analysis do not consider 3D azimuthal anisotropy present in shales. Ignoring anisotropy generally results in underestimation of stresses, which can lead to incorrect safe trajectories or mud-weights predictions. Similarly, completion design approaches used in conventional reservoirs do not take material anisotropy or the laminated nature of shales into consideration. This has often led to incorrect conclusions about lateral landing points and perforation intervals.

Development of BP’s Woodford Shale Play, an unconventional development, requires a significant quantity of water to drill and Complete wells, and thereby enabling production. The development of these shale plays requires 5-10 times more water than historical onshore developments; ranging from 100,000 – 150,000 barrels of water per well. The Woodford Shale Play utilizes roughly 140,000 barrels of water per well.

An integrated, systematic approach combining subsurface characterization with preliminary development planning was undertaken to evaluate a vast shale basin to enable identification of opportunities. Detailed data from well understood plays (eg: Horn River) were leveraged to construct a robust assessment in areas where there are only a few wells and no production data. Field outcrop work was also employed to augment subsurface analyses.

The goal in unconventional reservoirs is to contact as much rock as possible with a fracture or a fracture network of appropriate conductivity. This objective is typically accomplished by drilling horizontal wells and placing multiple transverse fracs along the lateral. While most parameters are considered in great detail in the completion design.

The rapid increase of shale gas exploration worldwide has created growing awareness of deficiencies in our understanding of fluid transport properties in these complex unconventional reservoirs. The production of shale gas requires a thorough understanding of the fluid conductivity properties of both, the fractured rock and the shale matrix. This contribution will focus on the matrix transport characteristics of selected organic-rich shales, differing in mineralogy, TOC (6-14 %) and maturity (0.6-2.4 %Ro).

Natural gas generated by thermal maturation of organic matter is for a part expelled and, for another part, retained in the source rock itself. The production of this retained part is the goal of the gas shale EP projects. It is now known that this gas is for a part free in the porosity and fracture network of the source rock but also adsorbed on the shale matrix and on the kerogen. Natural gas adsorption capacity is pressure and temperature dependant but for a kerogen it is also almost a linear function of its organic content (TOC).

For successful image analysis in unconventional reservoir characterization, combining the medical and micro-CT is an essential phase, i.e. the first is used in screening and locating desired depth for further studies, whilst the second can yield further details about the fine features with regards to porosity, mineralogy and heterogeneity and more.