Identifying injection gas breakthrough in multi-zone condensate reservoirs

Direct wellbore detection, not inferrence

Aug 1st, 2000
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Reflected light depends on refractive index of the medium. Appropriately placed thresholds in the waveform output help differentiate gas, oil, and water.
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Pressure reduction in gas condensate reservoirs ultimately results in the formation of liquid condensates. The permeability of the reservoir rock to this liquid results in formation fluid recovery problems, leaving potentially recoverable fluids in-situ.

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Lean gas is injected into some of these condensate reservoirs to vaporize the fluids and improve recovery of them. However, the increase in production does create a potentially difficult production performance problem. Evaluating where the actual formation fluids and injected breakthrough are occurring can be difficult, and highly subject to assumption(s). Confirming where formation fluids and breakthrough gas are entering the wellbore can offer unique zonal shut-off and/or stimulation alternatives.

Most alternatives for measuring gas in liquid wells, and liquids in gas wells, are limited by the ratios of the two phases in a given well sample. The traditional spinner alternative shows the relative change in velocity of fluids in the center of the wellbore.

One drawback of the spinner is that as the gas-oil ratio (GOR) increases, the accuracy of the measurement decreases. For example, in a horizontal well with gas on top and oil/water on the bottom of the wellbore, the spinner will only pick up half of the flow and only an average velocity can be computed.

The popular alternative is to add a pulsed neutron tool to the logging string to activate oxygen in the production stream, log it sequentially with multiple detectors, and yield a travel time (velocity) of the flow stream. In liquid producing reservoirs with GOR approaching zero, and gas-producing reservoirs with little liquid component, the spinner measurement does become more trustworthy.

Temperature, pressure


The tool directly measures variables such as bubble count and fluid velocity at any given point in the wellbore.
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Temperature probes also are used to assess where decreases in wellbore temperature are occurring, indicating gas entering the wellbore. This measurement however, is also affected by formation disposition outside of the casing, rendering it an ambiguous measurement at best. Nuclear measurements of wellbore density can be used, with some assumptions, to infer gas in the wellbore.

A gradiometric delta pressure measurement can be used to detect the pressure difference between two points vertically positioned within the wellbore. Variations in pressure can be interpreted as a different fluid entering the wellbore. The problem with this measurement is that it is limited in horizontal and highly deviated wells because of insufficient delta-height between the two pressure probes. The flow dynamics in small tubulars, high fluid velocities, and gas-oil ratio (GOR) affect the ability of these pressure probes to measure accurately. In high gas producers, you can get a qualitative, but not quantitative answer.

As the only alternatives available to the industry, the assumptions surrounding these measurements are taken as necessary evils. The amount of error introduced into the solution process is difficult to predict based on the number and type of assumptions involved. The biggest assumption, GOR, just happens to be one of the parameters needed for more accurate interpretation. Eliminate the assumptions, and a more accurate solution results. Directly detecting, not inferring, gas present in the wellbore yields a more reliable estimate of in-situ GOR, and thus a better estimate of formation-face flow properties.

The Gas Holdup Optical Sensor Tool (GHOST) tool from Schlum-berger is showing encouraging results in this type of application. The tool directly detects gas in the wellbore by analyzing the optical properties of the fluids present. These optical properties are not affected by fluid gravity, viscosity, pressure, or other factors, and are distinctive between all fluid types present in the wellbore. The use of voltage thresholds on the probe output signals allows for easy delineation of one phase from another also. For example, with two tool passes over a given formation interval, the distinction between gas, oil, and water is possible.

This represents a significant change in measurement philosophy. This measurement technique monitors time versus time, not actual measurements minus known measure- ments, with some assumptions of fluid densities included. This older method always requires a normalization process back to a known quantity - adding another assumption to the overall measurement. By simply measuring time and the actual gas hold-up, operating parameters such as pressure, temperature, viscosity, and dielectric quantities are rendered irrelevant to the final solution.

Fluid flow rate

The total producing fluids flow rate is proportional to the average cross sectional velocity of all fluid phases, the individual phase hold-ups, and the size of tubular.

Total producing fluids flow rate = (average fluid velocity) x (cross sectional area of tubular)

The average velocity can be obtained from a spinner if 100% of a single phase is present, or the FloView measurement. The total fluid holdup equals the summation of the individual phase hold-ups present and also comes from the tool. Pipe ID is of course, measured by a caliper tool.

Individual phase flow rate = (average fluid velocity) x (individual phase holdup) x (cross sectional area of tubular)

For gas, empirical slip charts can be used to get gas/liquid velocities from an average total flow measurement, or use the tool to measure directly the movement of bubbles in the total production flow. This yields a production flow rate, not just gas velocity.

Injection performance

An example of a multi-zone completion with oil production rate dropping under lean gas injection, occurred in the Cupiagua, rich gas condensate reservoir in Colombia. To regain acceptable oil production levels in this well, it was decided to determine if, and where, lean gas was entering the wellbore, increasing the total GOR of the comingled flow at the surface. A two-interval, multiple zone section of the completion was under scrutiny.

Re-completion alternatives, selective zonal isolation and stimulation, were being considered as possible remedial options. The popular evaluation alternative to date in this reservoir was using fluid density logs to detect where lean gas was entering the wellbore. This method was qualitative at best, but the only method historically used in the field. The FloView and GHOST tools were run in the same tool string to delineate water-hydrocarbon and gas-liquid ratios, respectively.

The popular assumption was that, due to the complex folding and faulting within the reservoir, the upper formation interval would have better communication with a nearby injector well, and be the point of lean gas breakthrough. The lower formation interval was assumed to still be producing at the original reservoir GOR. The contrary was found to be occurring. The upper formation interval was still producing at the original reservoir GOR, while the lower identified as the point of communication and lean gas breakthrough.

This led to a reperforation program in the reservoir, focussing on enhancing the upper formation interval's production capability. A noticed increase in oil production, with no increase in producing GOR, was observed. The up-front costs of logging and monitoring the well were recovered in less than two months, and extended the life of a well which would have not seen any perforation program at all for fears of perforating the wrong zone.

Phase out old technologies?

Some may see this as an opportunity to completely eliminate the need for nuclear measurements in production logging situations. This decision should be made carefully. Nuclear measurements measure a distinct quantity, sufficient in most cases, even with the assumptions they involve. One good thing about new techniques and technologies is that they can generate value in older technologies. As an example, a US Gulf of Mexico gas producing well, with a completion gravel pack, started producing water. The GHOST tool indicated an entry point in the horizontal section of the wellbore. A pulsed neutron tool indicated that the water was moving, implying influx from a lower point of entry. Using just one tool in the string would have led to a decision to seal off a substantial section of producing formation, using both tools kept this from happening.

More experience with the tool has further confirmed that a pulsed neutron measurement gives a good wellbore picture and a good look at what's going on immediately outside of the wellbore/casing, outside of the tool's area of focus. This helps in verifying a gas presence, and a potential future influx at any depth.

New applications of this measurement and evaluation technique are being realized. The ideal situation is a high rate gas well (with less than 1% liquid) starting to make liquid. Other applications include:

  • Measuring gas break-through in oil wells under gas injection
  • Any vertical or deviated well with three-phase production and the exact fluid entry profile is needed
  • Water entry in low or high-rate gas wells
  • Distinguishing gas from condensate
  • Identifying gas entry in commingled flow, sharing one separator
  • Evaluating water re-circulation problems.

Acknowledgements:

Lisa Silipigno, Schlumberger, previously served as PS Platform product champion and as a technical expert for the GHOST tool.

References:

Flores, J., Clifford, P., Castro, V., Loveland, R.; ASME ETCE/OMAE 2000 paper PR-050.

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