Nuclear magnetic resonance (NMR) data acquisition and interpretation in carbonate reservoirs is much more challenging than in sandstones, where it is a well-established technology. Heterogeneous porosity distribution, a broad range of pore sizes, a wide variety of complex textures, and low surface relaxivity combine to complicate the picture considerably. The successful practical application of NMR in these reservoirs requires the development of acquisition and interpretation techniques specifically suited to the task. In carbonate reservoirs dominated by intercrystalline or intergranular porosity, NMR can deliver accurate estimates of porosity, permeability, bound-fluid volume, and residual oil saturation. In vuggy, heterogeneous carbonates more complex interpretation models, based on the integration of whole-core and log data, are required for reliable answers. NMR answer products, based on these new techniques, are presented and validated with core data and by comparison to other logs. Introduction In many clastic reservoirs the CMR Combinable Magnetic Resonance tool has proven its ability to easily and accurately provide a number of answers not possible with conventional logging tools. From a single measurement of signal amplitude and transverse relaxation time (T2), it is possible to determine porosity, permeability, and bound- and free-fluid volumes and to estimate residual oil volumes. Extending this success to the carbonate reservoirs of West Texas is the focus of this study. CMR interpretation in these formations is not always straightforward and normal acquisition parameters are not necessarily sufficient to produce data relevant to the task at hand. For instance, under normal reservoir conditions, the oil signal and the water signal cannot be differentiated in most carbonates. Also, permeability estimated using the same simple treatment given to sandstones does not always match up well with core permeability. Despite these hurdles, quality answers are still attainable. The CMR* tools' accurate lithology-independent porosity is often critical in these complex carbonate reservoirs. Correct bound-fluid volumes are easily obtained using the right cutoff. Good permeability estimates are possible in carbonates, although this may initially require calibration versus core data and other logs in each field. And finally, a simple mud- doping procedure will allow the correct determination of residual oil saturation (ROS). NMR Petrophysics of Carbonates Petrophysically speaking, the most obvious difference between carbonates and sands lies in the heterogeneity of porosity distribution. In general, carbonates can be said to possess a wider range of pore sizes and geometries than sandstones, which are homogeneous and predictable by comparison. This gives rise to a number of physical properties in carbonates that directly affect NMR measurements. First, there are the properties that affect the T1 and T2 distributions of the formation. Because a wider range of pore sizes occurs in carbonates, the T2 distribution will generally be more dispersed than in sands. The largest of these pores will result in very long relaxation times; we show that this directly impacts logging speed and interferes with residual oil measurement. Additionally, an inherent matrix property of carbonates, low surface relaxivity, makes for longer relaxation times (Timur, 1972). Sandstone reservoirs consistently contain about 1% iron by weight. This results in a surface relaxivity of about 15 microns/s. By contrast, a typical carbonate matrix contains less impurities and has surface relaxivity in the range of 5 microns/s (Chang et al, 1994). P. 217^

Current best practices in North America's shale basins deliver inconsistent production results because of a lack of reservoir understanding along the lateral. Reservoir data is difficult and expensive to obtain in horizontal sections; therefore, most completions are designed geometrically, with little or no concern for reservoir heterogeneity. This leads to dramatic variability in productivity between neighboring wells, often described as the statistical nature of the play. In this study, we demonstrate a reliable, cost effective methodology that empowers shale operators with reservoir data on every well. This technique will enable operators to engineer their designs by using reservoir data on every completion, resulting in significant productivity improvement without any significant increased cost or inconvenience. This methodology leverages commonly available drilling measurements (rate of penetration, weight on bit, rotational speed, hole diameter, flow rate, differential pressure and standpipe pressure) and mud motor parameters (Kn, Tmax, ΔPmax) to derive Mechanical Specific Energy (MSE), using well established algorithms. The MSE parameter is then shown to be a good proxy for Unconfined Compressive Strength, a valuable reservoir parameter commonly used in frac designs. The MSE drives a facies-based answer product that enables the operator to position perforation clusters so that they breakdown at a common treating pressure, resulting in uniform fracture treatment within each frac stage. To date the technique has been applied successfully on over 60 wells. It is validated through comparison to openhole wireline logs and by comparing productivity to offsetting wells. The technique is shown to be superior to similar attempts done by using openhole wireline logs and production data confirms its accuracy and reliability. This study demonstrates that drilling data can be effectively used to derive reservoir parameters that lead to completion designs that produce superior production results. This methodology is the first application of drilling data to derive reservoir parameters that are then used to engineer a completion design. The significance of this development cannot be overstated, since it provides shale operators with the guidance they need to intelligently engineer their completions. The end result is significant productivity increases without any associated cost or inconvenience.

TX 75083-3836, U.S.A., fax 01-972-952-9435. ___________________________________________________________________________ AbstractThe Morrow gas sand reservoirs in southeast New Mexico have permeability values that can range across three orders of magnitude. The best wells are completed naturally; the poorer quality rock usually needs to be fracture stimulated to produce commercially. Early attempts to fracture stimulate the Morrow with water-base systems were only marginally successful. Previous studies have suggested that the poor fracturing response to water-base systems was due to a combination of water-sensitive clays and capillary pressure effects. Early theories were that the Morrow experienced reduced permeability as a result of clay swelling and high water saturations in the zones invaded by fracture fluid filtrate. These issues were addressed by using energized fracture treatments that included high quantities of CO 2 and methanol in the fracture fluid. Stimulation success with foams has not been consistent. Successful fracturing response to smaller hydraulic fracture jobs using foams has been observed in higher permeability wells where near-wellbore damage has been successfully bypassed. However, in lower permeability wells where fracture length is critical to stimulation success, foams have not provided economic stimulation results.Although foams were used to address water-sensitivity issues, undesirable side effects countered the foam benefits. Low viscosities, high friction pressures and high chemical cost resulted in increased screenout frequency and increased treatment cost.Early screenouts with low proppant concentrations have left many Morrow reservoirs producing at rates well below their potential. To achieve optimum inflow potential, a fluid system is required that is capable of developing adequate hydraulic width and transporting larger volumes and concentrations of proppant.Water-base fracturing fluid technology has come a long way since the early days of Morrow fracture stimulation. Advances in both fluid selection and fracture design now make it possible to use a water-base system to achieve successful stimulation results in the Morrow in southeast New Mexico. The net result of this engineering approach is improved stimulation results with lower treatment cost. Two examples of successful applications of modern fracturing techniques demonstrate that operators in the Morrow of southeast New Mexico have a choice of fracturing fluids other than CO2 foams.

This paper (SPE 51329) was revised for publication from paper SPE 38740, first presented at the 1997 SPE Annual Technical Conference & Exhibition, San Antonio, Texas, 5-8 October. Original manuscript received for review 7 October 1997. Revised manuscript received 1 June 1998. Paper peer approved 15 June 1998. Summary Nuclear magnetic resonance (NMR) data acquisition and interpretation in carbonate reservoirs is much more challenging than in sandstones, where it is a well-established technology. Heterogeneous porosity distribution, a broad range of pore sizes, a wide variety of complex textures, and low surface relaxivity combine to complicate the picture considerably. The successful practical application of NMR in these reservoirs requires the development of acquisition and interpretation techniques specifically suited to the task. In carbonate reservoirs dominated by intercrystalline or intergranular porosity, NMR can deliver accurate estimates of porosity, permeability, bound fluid volume, and residual oil saturation (ROS). In heterogeneous carbonate reservoirs more complex interpretation models are required, normally based on the integration of whole core and log data. NMR answer products, based on these new techniques, are presented and validated with core data and by comparison with other logging measurements. P. 438