Show evaluation

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Development Geology Reference Manual
Series Methods in Exploration
Part Wellsite methods
Chapter Show evaluation
Author Paul A. Daniels, David B. Finnell, William J. Anderson
Link Web page
Store AAPG Store

Show evaluation at the wellsite is important because it represents the first, and sometimes only, opportunity to assess the potential economic viability of a particular well or prospect. Decisions of considerable economic impact are made based on show evaluation results, including formation testing, setting pipe, participation elections, and lease acquisition or relinquishment.

Mudlogs are the most useful wellsite evaluation tool due to the integration of lithology, rate of penetration (ROP), gas recordings, and oil description (see Mudlogging: the mudlog).

Wellsite show evaluation relies on the following:

  • Detection of formation gas or oil
  • Detection of hydrocarbons in drill cuttings
  • Knowledge of drilling and wellsite activities
  • Geological knowledge of the interpreter

Figure 1, a show evaluation form, summarizes some of the criteria commonly used to evaluate a show. Note, however, that the presence or absence of a recordable show does not absolutely determine hydrocarbon producibility. For example, zones of good porosity and permeability that yield no show may still be viable hydrocarbon-bearing reservoirs. Conversely, poor porosity-permeability zones that have gas increases may be nonproducible. For the most effective formation evaluation, wellsite shows of all types should be integrated with the results of postdrilling logging and testing.

Figure 1 Show evaluation form. (Copyright ©1992 by Paul A. Daniels, Jr., and Diana Morton-Thompson. Used with permission.)

Gas detection

A gas show is a recorded increase in gases above a baseline amount indicative of the hydrocarbon potential of the formation. This increase is assumed to be independent of any borehole drilling or circulation process. Table 1 summarizes the nomenclature of gas that can result from the drilling process. The presence of these gases should not be confused with a “show.”

Table 1 Types of gas that result from the drilling process
Type of Gas Description
“Zero” gas Gas present in the mud circulating system when the bit is off-bottom and there is no vertical movement of the drill string. This reading results from the liberation of gases from the mud system or from the recycling of previously encountered gases in the wellbore. Although a “zero” gas value will constantly vary, it acts as a starting point for evaluating any subsequent formation gas shows.
Background gas Gas that reflects the geological character of a consistent lithology. Background gas readings incorporate gas contributions due to the formation, but also those included as zero gas. Gas from the formation is due to the crushing of the rock as it is being drilled and typically has a low volume. These gas readings are plotted on the mudlog as background gas and represent the relative baseline against which all other gas shows are compared.
Liberated gas Gas that is produced by the drilling process due to the crushing of the rock formation by the drill bit.
Connection gas Formation gas that enters the wellbore while drilling and circulation are halted to make a connection. For this condition to occur, the contributing formation must be underbalanced by the mud system at some point within the borehole.
Produced gas Formation gas that enters the wellbore while drilling and circulating. This gas represents an underbalanced formation and, if left alone, will cause a blowout.
Trip gas Formation gas that enters the wellbore when the drill string is being “tripped” or pulled out of the wellbore. The contributing formation must be underbalanced at some point within the wellbore; such underbalance is due to the “swabbing” effect caused by pulling the drill string out of the hole.
Recycled gas Gas that has been previously contributed to the borehole and not completely removed from the mud circulation system by surface equipment (such as a gas trap or degasser). Such gases that remain in the mud system are pumped back down the borehole to be subsequently re-recorded by the gas detection equipment. This recycled gas can usually be recognized because the “show” will be detected one full circulation cycle later than originally encountered and will appear more diffuse in character.

The analysis of a gas show begins with the detection of hydrocarbon gases that are the result of drilling a specific interval. The amounts and compositions of these gases are recorded on gas detection and chromatograph equipment. The simplest and most widely utilized gas detection device is the hot wire. This type of detector can provide readings of the total gas present (in units or percentage) as long as the gas concentrations are low enough that the equipment does not become “saturated” (on most hot wire equipment, gas percentages must be below a certain maximum for accurate readings).

Flame ionization gas detector (FID) equipment operates on a different principle and does not saturate. An FID detector can also provide chromatographic analysis of the gases. Chromatograph recordings normally distinguish the amounts of methane (C1), ethane (C2), propane (C3), isobutane (IC4), normal butane (NC4), isopentane (IC5), and normal pentane (NC5). The greater the amount and percentage of a gas show represented by the heavier hydrocarbons (particularly C4 and C5), the greater the potential for oil production from that zone[1]. However, the presence of anomalous, noncombustible gases such as nitrogen or carbon dioxide can attenuate hydrocarbon gas curves.

Ratios of the different gases are often used to do the following:

  • Support show identification
  • Cross-check lag time calculations
  • Discriminate among different show zones
  • Indicate possible “richness trends”
  • Identify fluid content
  • Provide stratigraphic correlation

Various gas ratios can be used depending on the data available. The most common gas ratios used are those with the most separation (C5/C1) and those with the heaviest composition (C4/C1 or C5/C1). Because gas ratio analysis is empirical in nature, it can sometimes prove inconclusive. However, the following “rules of thumb” can be useful[2]:

  • Zones with a high C1 value may represent dry gas, coal, biogenic gas, or a water wet zone.
  • Wet gas zones commonly have a C1 /C3 ratio that is higher than the C1 /C4 ratio.
  • Nonproductive zones tend to have a ratio trend where subsequent values are lower than preceding values.

Factors affecting gas detection

Factors that affect the quality or presence of gas shows include mud weight and wellbore flushing, operation of the surface mud system, and accuracy of calculated lag time (see chapter on “Mudlogging: Gas Extraction and Monitoring”).

Mud weight and wellbore flushing

Near wellbore flushing occurs when the pressure or weight of the mud column exceeds the fluid entry pressure of the formation (for information on calculating mud weight, see chapter on Wellsite math in Part 3). This flushing by mud filtrate occurs above and ahead of the bit and is a function of time. If the mud system is overbalanced, gas shows can be reduced or totally suppressed. Even in a carefully balanced mud system where the fluid loss is minimized and the radius of wellbore flushing is small, problems can still occur in evaluating gas show quality if the rock's petrophysical properties are not considered. In zones of low effective porosity, even relatively small volumes of filtrate loss may result in deep invasion profiles. This causes a zone with a good gas show when drilled to recover only mud filtrate or to appear water saturated when later tested or electric logged. In zones of high effective porosity and permeability, the rocks will initially be flushed, then return to their native state soon after drilling, with little or no gas liberated. This causes a zone with minimal gas show when drilled to appear productive on electric logs or when later tested. Low permeability overpressured zones will not flush and will give high gas readings.

Information that can aid in the interpretation of flushed anomalies includes the following:[2]

  • Pump pressure
  • Jet nozzle size(s) of the bit
  • Mud rheology (plastic viscosity and yield point)
  • Mud weight and effective circulation density
  • Formation balance gradient (mud weight required to equalize formation pressure)
  • Mud filtrate (water loss) amount
  • Lithology descriptions of
    • visual porosity (absolute, effective)
    • porosity description (type, size, distribution)
    • cementation (type, degree, mineralogy)

Surface mud system

Flowline

A high degree of degassing takes place in the conductor pipe and flowline. Loss of gas from the mud to the atmosphere also occurs extensively in the flowline[2], particularly when

  • The flowline is not filled with mud
  • Changes in flowline slope promote turbulence
  • Sections of flowline are open to the atmosphere
  • The flowline enters the possum belly above mud level

In extreme situations, the amount of gas lost from the mud system prior to analysis can be so great that any resultant shows are significantly biased.

Gas trap and agitator

This equipment is usually in or around where the flowline enters the possum belly. If the equipment is not operational (plugged orifices or lines, not powered-up, etc.), insufficient gas may reach gas analysis equipment to allow for an accurate analysis (see Mudlogging: gas extraction and monitoring).

Gas analysis system

If the detection and analytical equipment are not properly and constantly maintained and calibrated, inaccurate gas detection and analyses can result. Because there are numerous ways that the drilling, the gas-gathering system, and equipment wear can affect this analytical equipment, a complete system check and calibration is recommended on each tour.

Lag time

It is of the utmost importance to know the exact depth that all drill cuttings samples and gas are coming from within the borehole (for information on calculating lag time, see Wellsite math).

Cuttings evaluation

In many wells, drill cuttings collected may represent the only subsurface data available for geological interpretation. After a detailed lithology description, cuttings are analyzed for hydrocarbon indications (see Mudlogging: drill cuttings analysis). Traces of gas and oil in the cuttings represent formation hydrocarbons that have not been flushed by the drilling fluid. Gas in cuttings is analyzed by grinding a measured amount (approximately 100 mg) of unwashed cuttings in a blender, with any liberated gases analyzed by the standard gas detection system. This analysis is often divided into two components: total gas, comprising all combustible gasses; and petroleum vapors, comprising C2 through C5. This type of analysis can indicate the amount and composition of gases in the formation, even if the larger rock pores are flushed.

Evaluation of oil in cuttings is performed on unwashed and washed bulk cuttings and on individual grains. Evaluation includes visual inspection and analysis using a microscope and ultraviolet (UV) box. Oil shows are described by their physical properties of visual stain, fluorescence, cut, and odor. Care must be taken always to evaluate hydrocarbon shows in cuttings with respect to their petrophysical properties (see review by [3].

Visual stain

Staining of the drill cuttings by oil is an indication that hydrocarbons have been in the formation at some point in time. The lack of sample staining, however, does not prove that a reservoir lacks producible hydrocarbons. The amount and distribution of staining is a function of the reservoir porosity and permeability. Stain color can be related to oil gravity, with darker staining indicating heavier hydrocarbons. If a stained sample does not fluoresce or cut, then this indicator is classified as thermally “dead oil” and is not considered a show. Staining is described in terms of its color, distribution, percentage of sample stained, and fluorescence (if any).

Fluorescence

Fluorescence refers to the color of the drill cuttings under UV light of various wavelengths. A lack of fluorescence, however, does not prove the absence of hydrocarbons in the zone of interest. Care must be taken to distinguish hydrocarbon fluorescence from natural minerals or artificial materials (Table 2). Fluorescence is described in terms of its color, intensity, distribution, and percentage of sample fluorescing.

Table 2 Fluorescence of common minerals and artificial materials
Mineral or Material Fluorescence Color
Minerals[2]
Dolomite, magnesian limestones Yellow, yellowish brown to dark brown
Aragonite and calcareous mudstones Yellow-white to pale brown
Chalky limestones Purple
Foliated shales Tan to grayish brown
Anhydrite Blue to mid-gray
Pyrite Mustard yellow to greenish brown
Artificial Materials
Diesel fuel Dull brown
Pipe dope Bright blue
Oil-based muda Varies
aSamples of oil-based mud and other petroleum products used around the wellsite should be routinely sampled and examined under UV light to avoid potential confusion with hydrocarbon shows from the rocks.

Cut fluorescence

A cut is the oil liberated from drill cuttings when a solvent is added. A common solvent used for inducing cuts is chlorothene; others include acetone, petroleum ether, alcohol, hot water, and acid. Note that because of its toxicity, carbon tetrachloride should not be used. Most solvents are flammable, and great care must be taken to handle these materials safely. A cut is performed while viewing the rock samples under both normal and UV light. Solvent cuts allow deductions to be made regarding oil mobility and reservoir permeability. A cut is described in terms of its natural color, fluorescence color, “liberation” rate and intensity, and residue. All suspected hydrocarbon-bearing intervals should be tested for cut fluorescence. This is because there may be a positive cut fluorescence test when other hydrocarbon detection methods fail.

Odor

The odor of hydrocarbons may be present even in the absence of any other hydrocarbon indicators. This condition is most noticeable during the sample drying process, when lighter hydrocarbons are driven off. Odor is described as faint, fair, or strong (indicative of heavier hydrocarbons). Keep in mind that methane through butane have no odor.

Factors affecting cuttings evaluation

Attention to differential pressure (over- or underbalanced), ROP, hole size and condition, contaminants, recycling, etc. is necessary for proper cuttings evaluation. Also, as there is no substitute for representative cuttings samples that are correctly correlated to depth, the importance of an accurate lag time cannot be overemphasized.

Drilling operations and wellsite activities

Wellsite evaluation of hydrocarbon shows requires clear and constant communication with vendor and drilling company personnel.

Drilling activities that represent shows include

  • Flaring gas
  • Oil in the pits, tanks, or mud system

Activities that may not represent a show include

  • A drilling break or increase in the ROP (see Rate of penetration)
  • An increase in the mud tank level

Activities that are not a show but can be mistaken for a show include

  • Rig maintenance (lubrication, washing diesel into the mud pits)
  • Mud additives
  • Lowering mud weight

Activities that can lead to overlooked shows include

  • Drilling with a constant ROP (controlled drilling)
  • Overbalanced mud system
  • High mud filtrate loss
  • Losing circulation
  • Bypassing the shaker
  • Electrical power fluctuations

See also

References

  1. Ferrie, G. H., Pixler, B. O., Allen, S., 1981, Well-site formation evaluation by analysis of hydrocarbon ratios: 83rd Annual General Meeting of the Canadian Institute of Mining and Metallurgy, Paper 81-32-20.
  2. 2.0 2.1 2.2 2.3 Exploration Logging, Inc., 1985, Mud Logging: Principles and Interpretations. Boston, MA, IHRDC, 92 p.
  3. Swanson, R. G., 1981, Sample examination manual: Tulsa, OK, AAPG Methods in Exploration Series No. 1, 35 p.

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