NMR-derived permeability aids frac design

Stephen Schubarth, Peter O'Shea
Halliburton Energy Services
Houston

Nuclear magnetic resonance logging (NMR) provides an accurate and continuous permeability measurement that is timely enough for use in hydraulic fracturing design prior to completing a well.

An accurate estimate of in situ formation permeability can lead to cost savings and production increases in wells requiring hydraulic-fracturing stimulation.

The cost savings and increased profitability can far exceed the cost of acquiring this reservoir description information.

The measured permeability is used in determining well deliverability.

Frac design

Having an accurate estimation of a well's deliverability prior to completing the well can reduce field development costs. Knowledge of the deliverability can lower stimulation treatment costs and eliminate completion costs altogether for wells that are not capable of paying them out.

Too often a "one-size-fits-all" or "cookie cutter" approach is applied to field development. Many operators perform the same standard treatment on all wells in a particular field, letting the resulting production be what it may. These operators gamble that the gross overall field production will be profitable by having "winners" compensate for "losers."

Developing the optimal completion design for each prospective well bore pay interval, using accurate data, is a much sounder approach and can dramatically improve profitability.

Accurate formation-permeability and fracture-geometry information is the most critical factor governing the design and application of hydraulic-fracturing programs.

Soon after commercial hydraulic fracturing of subsurface oil and gas reservoirs began, questions arose regarding the best treatment sizes and types. The fundamental determination of formation deliverability is based on the following two data sets:

1. Fracture geometry
2. Formation permeability.

The answer requires sophisticated mathematical models that depend directly on their input data. The more accurate the data, the more closely fracture treatments approach optimal design and commercial success.

Data sources

Pertinent data originate from many sources such as:

• Core analyses
• Field experience
• Prefracture production tests
• Pressure transient and log analyses.

Expenses vary for collecting different types of data.

Some sources actually interfere with fracturing. For example, a perforating program for a natural-flow test may not be the ideal perforating program for a fracture treatment.

Logs provide a unique data source. Rock property logs have been used to estimate in situ stresses, Young's modulus, and Poisson's ratio. The resulting data, when combined with on-site measurements from field fracture treatments, leads to reasonable estimates of fracture geometry.

Historically, the determination of formation permeability is more difficult. Accurate estimation of in situ formation permeability has in the past required costly core gathering and analysis or, alternatively, some type of production test.

Formation permeability sometimes can be estimated from mini-frac analysis, but by the time analysis is completed, the treatment volumes to be pumped usually are already designed and on site.

What is needed for optimal, customized completion designs are accurate permeability estimates for each well bore interval.

The magnetic resonance imaging log (MRIL) provides an accurate and continuous permeability measurement that is timely enough for use in designing hydraulic fracturing treatments.

NMR logs

In the medical industry, nuclear magnetic resonance (NMR) technology uses a powerful magnet and a radio-frequency transmitter to pulse electromagnetic energy into a patient's body. This nonradioactive technique, commonly known as magnetic resonance imaging (MRI), manipulates hydrogen protons in a way that causes them to emit a detectable signal.

A computer then converts the signals to an image that is used for diagnosis of medical conditions.

The oil and gas industry is now applying this technology to accurately measure several key factors that influence a well's ability to produce commercial quantities of oil and gas.

In addition to permeability, NMR logs provide measurements of porosity and irreducible water saturation, as well as identification of fluid type and viscosity changes.

Permeability distributions

A convenient but extremely simplistic assumption would be to believe that all wells in a field have the same permeability.

This premise is erroneous. In fact, permeability can vary from foot to foot in each well bore, and highly permeable intervals even can exist in low-permeability ("tight") formations.

Some of these intervals may be so permeable that they will not benefit from hydraulic fracturing.

Fig. 1 [63,418 bytes] shows first year gas-production distribution for the following three "tight" gas fields:

1. East Texas Cotton Valley
2. Moxa Arch Frontier in the Rocky Mountains
3. Western Oklahoma Red Fork.

These plots clearly demonstrate the wide range of deliverability, and therefore permeability, in these fields.

Net pay is not constant from well to well, and pressures may vary somewhat. If net pay were the only cause of variation, it would be possible to avoid unprofitable completions.

Cost cutting

Cost cutting is key to survival in the current business environment, especially in such marginally economic areas as the fields in Fig. 1.

An in-depth discussion of drilling-cost reduction exceeds the scope of this article, but the significant reductions in completion costs can more than compensate for the slightly higher logging costs associated with NMR technology.

The increased accuracy of reservoir description and deliverability forecasts made possible with NMR means more effective spending and recovery of completion funds. The following example of a hypothetical field with the same production distribution as the Moxa Arch Frontier and East Texas Cotton Valley formations demonstrates this value.

Table 1 [23,004 bytes] presents general reservoir properties for the hypothetical case. The well-to-well variation in formation permeability correlates to the variation in production distribution.

The limited scope of this hypothetical discussion assumes all other reservoir properties are constants.

Before development began, the recommended fracture-stimulation treatment design in a 100-well program assumed a median 0.03-md permeability.

Stimulation cost for this 450-ft fracture interval was $178,500. This sum, together with a dry-hole cost of $350,000 and fixed completion costs of $250,000, bring total costs to $778,500/well, or a total expenditure of $77,850,000/100 wells.

The cost of increasing fracture-zone length to 550 ft would be $78,000, while savings of pumping into a 350-ft-thick interval would amount to $62,000.

Remember, too, that a pipe-setting decision can be made on wells that will not pay out completion costs.

Fig. 2 [70,909 bytes] compares the distribution of net present values (NPVs) for the 100 wells drilled and completed under the 450-ft "cookie cutter" treatment design to the NPV distribution if each fracture treatment had been optimally designed with precise data.

The difference may not seem significant at first glance. The comparison reveals, however, an increased profit per well of almost $70,000, with an average well-cost reduction of $29,000.

The discounted return on investment (ROI) increased from 1.29 to 1.40.

The costs of NMR logging were excluded from this analysis. Had they been included, these costs would have been substantially lower than the calculated profits.

Similarly, benefits to be found in wells with multiple pays were also excluded. In these cases, stimulation savings can be even greater than shown by the example.

The Authors