This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.

Designing an acid-fracturing treatment is similar to designing a fracturing treatment with a propping agent. Williams, et al.[1] presents a thorough explanation of the fundamentals concerning acid fracturing. The main difference between acid fracturing and proppant fracturing is the way fracture conductivity is created. In proppant fracturing, a propping agent is used to prop open the fracture after the treatment is completed. In acid fracturing, acid is used to "etch" channels in the rock that comprise the walls of the fracture.

Mass-transport deposits (MTDs) are sedimentary, stratigraphic successions remobilized after initial deposition but before substantial lithification and transported downslope by gravitational processes as non-Newtonian rheological units. In the complete paper, the authors present an openhole advanced formation-evaluation approach that enables assessment of tight-matrix and natural-fracture systems at a level not previously accomplished in these types of geological formations. The considered wildcat project by Petroleos Sudamericanos is in the Lower Magdalena Valley hydrocarbon province in Colombia. From a stratigraphic point of view, the targets belong to tertiary deposits from the lower Neogene. Gravity-driven processes are complex and include creep, slide, slump, debris flow, and multiphase granular flows.

Natural fractures maintain a significant role in many hydrocarbon plays, in both conventional and unconventional reservoirs. In exploration and development scenarios, specific fracture properties, such as orientation and density, are important. However, more critical is their internal architecture: are the fractures open to fluid flow or filled with minerals? Borehole microresistivity imaging tools are widely used to determine these fracture characteristics. In wells drilled with water-based muds, open fractures are filled with conductive borehole fluid that enables distinguishing open, water-filled fractures from resistive, mineral-filled fractures and the surrounding rock. However, many wells today are drilled with oil-based muds. In this case, mineral-filled fractures and oil-based-mud-filled fractures are equally highly resistive and cannot be directly distinguished using resistivity images only. The latest-generation wireline oil-based-mud microresistivity imagers operate in the megahertz frequency range, radiating the electrical current capacitively through the nonconductive mud column and delivering photorealistic borehole images. Both electrical conductivity and dielectric permittivity components constitute the measured signal, from which button standoff, formation resistivity, and dielectric permittivity are inverted. Our example case shows highly resistive, high-angle fractures from the resistivity images with their orientation and density. The standoff image determines if the mud column penetrates the fracture plane, showing an apparently high standoff compared with the surrounding rock. If the standoff appears high in the fracture plane, the fracture is classified as open to fluid flow. However, are these fractures indeed fully dilated and open, or are they filled with different materials - are they partially mineralized with calcite and partially open, filled with mud? To further determine the fracture fill and susceptibility to fluid flow, a new workflow employs the material dependency of the relative dielectric permittivity. The relative permittivity is estimated as a function of resistivity and frequency pixel by pixel on the resistivity image. The estimate formula is based on several hundred laboratory measurements on core plugs with different fluid saturations and salinities. The resulting borehole image enables distinguishing materials in the volume of investigation, where low values correspond to mud-dominated oil in open fracture planes, medium values correspond to rock-forming minerals, and high values are attributed to shales and other clay-rich rocks. Fracture planes filled with patches of both low- and medium-permittivity values are classified as partially open.

A British independent bet its future on proving that fractured basement formations could produce large amounts of oil and gas. Based on its first two wells, the proposition that these highly fractured layers of awful-quality reservoir rock can produce billions of barrels of oil is looking very unlikely, but there might be something of value down there. Last April, Hurricane Energy predicted those two development wells could easily produce 17,000 B/D of oil from rock it said held "half a billion barrels of oil." Now Hurricane's ambitious plans and its identity as "basement reservoir specialists" are in tatters. The initial wells were productive but much of what was coming out of the lower one--205/21a-7z--was water.

The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field.[1] Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking.

The dynamics of full-field development for multi-target Midland Basin acreage have a tremendous impact on the total EUR per section. Depletion can be hard to model and results are often only clearly seen after a significant amount of wells has been drilled. Traditional models assume unrealistic fracture geometries and do not account for the amount of variability in the geology. Using a FracStar surface array, acoustic data were acquired during the treatment of an eight-well pad in three target formations. Microseismic events and the created fracture network were imaged and allowed for a realistic reservoir model due to the accurate modeling of the discrete fracture network, distinction between propped and unpropped fractures, and the calculated permeability enhancement due to the treatment.

Figure 1[1][2] shows the type of production response that is possible when applying a polymer gel treatment to a waterflood injection well to improve sweep efficiency. The figure shows the combined production-response of the four direct offsetting production wells to the gel-treated injection well. The gel treatment was applied for waterflood sweep-improvement purposes to the naturally fractured Embar carbonate formation surrounding Well O-7 of the highly mature SOB field in the Big Horn basin of Wyoming. The wide variations in water/oil ratio (WOR) and oil production rate are quite common in many of the well patterns of this highly fractured reservoir. Sydansk[2] provides more details regarding the 20,000 bbl gel treatment.

The Advanced Energy Consortium (AEC) is an internationally recognized research organization dedicated to achieving transformational understanding of subsurface oil and natural gas reservoirs through the deployment of unique micro- and nanosensors (Johnson 2010). The AEC was formed in 2008 by the University of Texas at Austin's Bureau of Economic Geology and major oil and gas companies to focus on conducting precompetitive research to address challenges in upstream exploration. Multiple sensor-technologies are being developed by the AEC and investigated in several applications, including wellbore characterization, hydraulic fracturing, waterflooding, enhanced oil recovery (EOR), and interwell reservoir characterization. The vision is exciting as it explores technologies for oilfield rocks in harsh environments, including high temperatures, high pressures, small pore spaces (30 nm to 10 µm), high salinity, and varied pH conditions. Since January 2008, more than USD 45 million has been invested in AEC research projects.

The oil industry must continually and dependably meet the hydrocarbon demand as most of the easy oil is gone and future production will come from more challenging reservoirs that require complex technologies. Hydrocarbon producers must be cost-conscious, acknowledging that oil prices might not reach the high levels of the past, and as an industry ensure that oil prices do not drop significantly for long-term projects to remain sustainable. Also, in the age of ever increasing environmental scrutiny, the industry must be clever to minimize its environmental impact despite the associated added costs. To sum up these facts: In the next half a century or so, how do we maximize hydrocarbon recovery from challenging carbonate reservoirs while limiting our environmental footprint and keeping profit margins sufficiently high? In early February, porous media experts from all over the world assembled at the King Abdullah University of Science and Technology (KAUST) in Saudi Arabia for a research conference to find answers.