By modeling NMR outputs synthetically, a new software system can determine permeability with conventional log data.

In the ongoing research and development process to enhance formation evaluation, establishing a strong relationship to permeability has always been a key goal. In the early 1990s the commercialization of nuclear magnetic resonance (NMR) logging in the oil and gas industry provided the first such link through the direct measurement of the fluid volume and the distribution of that fluid in the rock.

This link to permeability set the stage for several refinements in NMR over the last decade, the results of which have dramatically shaped how the industry views bypassed pay. NuTech Energy Alliance Ltd. (NuTech) was founded on the principles of applying NMR technology to conventional log data. Its proprietary software models NMR outputs synthetically, allowing companies to take a "new look" at fields that have not had the benefit of such NMR measurements. With the release of an additional module in the spring of 2004, a true textural permeability is now available.

By utilizing conventional log data, textural or pore size changes within the reservoir can be detected and modeled. For example, the utilization of this technology in the Barnett Shale in North Texas resulted in an 88.5% correlation coefficient when comparing pore size distribution in the free-fluid volume (besides a 90% fit with full core analysis) with production. This is compared with a previously recorded 66-70% optimum correlation coefficient in one of the most difficult formations in the United States.

In major oil and gas producing regions including the Rocky Mountains, Texas, Louisiana, Mid-Continent and Alaska, field testing and validation is based on a historical data base of more than 10,000 wells. All of the data is readily available to demonstrate the effectiveness of textural permeability; including core data, production data and conventional NMR log data.

The original goal of NMR technology in the early 1990s was to utilize the base measurement of the NMR device (T2) to achieve a T2 permeability or grain size-related permeability. However, it was realized early on that the T2 distribution directly measured by the tool was affected by hydrocarbons through gas/oil polarization and diffusion effects, thereby not allowing for a true grain size permeability model. The pore size components or textural variations existing with the free fluid volume could not be effectively measured. Therefore, NMR had to rely on the permeability relationship developed around the free fluid volume (free fluid permeability).

The new system, modeled from a suite of conventional log data, is not susceptible to the same hydrocarbon effects as an actual NMR tool. By using the geometric mean of the pore size distribution, true textural permeability can be determined which is even more accurate than the traditional free fluid permeability calculation. Through the addition of the new textural dimension into the formation evaluation picture, reservoir quality can be further fine-tuned (as well as its relationship to permeability) to allow better decision-making in most markets where permeability is the key variable to achieving enhanced production.

Stimulation design

It is now possible to take a consistent petrophysical evaluation, governed by the textural product, and compare the completion effectiveness across a field. With a consistent petrophysical evaluation, a new process can be applied in an effort to properly characterize the reservoir, scorecard past completion techniques, predict production results corresponding to variable completions and avoid failures. This completion process yields a truly optimal completion design, unique to each individual zone in a particular well and field.

Each well responds differently, and these differences are noticeable on the log responses. By properly characterizing each specific reservoir, the completion can be tailored to each individual zone. The process allows completion engineers to stop focusing solely on what was done in the area in the past and what was seemingly successful and focus on each unique well. Therefore, with the combination of the textural permeability calibrated to production and the enhanced stimulation process, true completion optimization can finally be achieved.

In order to establish a relationship to completion techniques and their corresponding production response, even a properly normalized field well bore, and accurate in-situ stress profile must be utilized. Within the new process, a synthetic sonic measurement, calibrated to existing measurements in each basin, is implemented to create the in-situ stress profile.

From this in-situ stress profile, a relationship can be drawn between treatment size, dimensions created by the treatment and treatment cost for each stimulation stage. The textural permeability model, calibrated to field production, can be coupled with these relationships to predict production responses associated with each treatment. Proprietary software allows up to 50 different treatment sizes and resulting production profiles to be quickly modeled for a specific frac interval. From this step, an optimal job size can be determined.

This technique is an evolving process in which valuable information can be extracted from previous models and improved upon in subsequent wells through additional information such as build-up, mini-frac, production information, tracer logs or production logs. This aids in accelerating the learning process in a given field or area.

Field-proven applications

Ultimately, the test of whether bypassed pay can be more effectively located is in field applications. Two examples are telling. In one instance in the Rocky Mountains (Wyoming), the operator was concerned both about quantifying permeability and identifying moveable water.

Previously, the operator committed to a costly and unfocused completion that centered on perforating and stimulating all well zones with no regard to potential. This time, however, using the synthetic NMR data, not only were zones with sufficient permeability identified, but moveable water throughout the well bore was successfully located as well. As a direct result, frac fluids were focused exclusively into zones identified as being at irreducible and with sufficient permeability. Bottom line? The operator lowered completion costs and increased production.

In South Texas' Colorado County, the South Wilcox Sand section at 11,000 ft (3,355 m) consisted typically of very tight rock requiring fracture stimulation. In these circumstances, there is a reluctance to stimulate a well and possibly fracture into a low resistivity "wet" zone when it's difficult to know whether low resistivity is a result of a wet formation or a textural or grain size change.

In this particular well, a good zone at 10,900 ft (3,325 m) was known, but due to the tighter rock fracture stimulation was required. Considering the low resistivity at this depth, was there moveable water in this zone? These new textural tools both indicated no free water in the zone from 11,010 ft to 11,090 ft (3,358 m to 3,382 m) and identified #2 risk-weighted hydrocarbon bearing zones at an Rw of 0.07.

Subsequently the zones were fracture-stimulated and tested at 1 MMcfd with no water, which allowed the operator to come up the hole and frac-stimulate the upper three zones that had been identified as #1 and #2 risk weighted zones - without risking breaking into water zones. The three zones were frac-stimulated and, with the lower three zones, tested 4.5 MMcfd with no water.

Conclusion

Utilizing this innovative textural relationship and enhancement, which radically changes the way that bypassed pay is viewed, many new opportunities for oil and gas companies have opened since most of the work originates from older log data. For example, it can be used for acquisition screening, to assist in pipe-setting decisions, where to collect more data and/or where to perforate, and now how to achieve the best fracture stimulation design, to name but a few.

The advent of NMR signaled the changing environment in which companies attempted to enhance their operations. For a decade, NMR successfully measured the quantity of free and bound water within a reservoir as well as computing permeability and calibrating the permeability relationships with core.
Research and development has produced the first true textural petrophysical system with the much sought after pore size permeability. The commercial applications in basins from Rocky Mountains to south Texas have achieved an 88.5% to 95% correlation coefficient in these markets, which is a readily acceptable result in industry efforts to best risk assess potential reserves in existing or developing assets.

For more information about NuLook, NuLook Textural Vision (NTV) and NuStim, visit www.nutechenergy.com.

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