Allocating Commingled Production Using Oil Geochemistry

OilUnmixer™ software for allocation of commingled production has been subjected to numerous blind tests by numerous petroleum companies. A blind test is when an outside laboratory prepares artificial mixes of multiple oils, and then OilUnmixer™ software is used by OilTracers LLC to determine the contribution of each oil to the mixes (with OilTracers LLC having no advance knowledge of what the "answer" is). Numerous blind tests have shown that OilUnmixer™ typically yields allocation results that are within 1-5% of the actual result, even when the oils being commingled are extremely similar in composition.

There are many advantages to using oil geochemistry (vs. production logging) to allocate commingled production. At OilTracers, we use geochemical methods to solve two types of production allocation problems:

Assessing the relative production from multiple pay zones in a given well

• Cost advantages: Geochemical techniques for allocating commingled production from multiple zones in a single well typically result in a >90% cost savings relative to production logging (McCaffrey et al., 2006).  Geochemical techniques cost  $500 to $1500 per well per allocation, while the alternative (production logging) usually costs >$20,000 per well.  The greater cost of the production logging approach is due not only to the costs of running the log, but also to the associated rig costs, and the costs of lost production during logging. These costs are not applicable to the geochemical approaches. Other advantages of the geochemical techniques include:
• Detection of zone performance problems at any point during the life of a well: The low cost of the geochemical techniques for production allocation allows field engineers to monitor production frequently over long periods (weekly, monthly, quarterly).  This ability to monitor continuously the relative performance of discrete pay zones allows early identification of zone performance problems.  The much higher cost of production logging limits that technique to infrequent use; therefore, production logs typically provide only a "snap shot" of the production origin at the time the log was run, and not a continuous performance history.
• Applicability to vertical, deviated and horizontal wells:  Geochemical techniques are applicable not only to vertical wells, but also to highly deviated and horizontal wells.  In contrast, production logging is problematic at high deviations, and especially difficult at deviations greater than about 70 degrees.
• Applicability to pumping wells:  Geochemical techniques can be applied to all types of pumping wells (including those with tubing-deployed electrical submersible pumps, and progressive cavity pumps).  In contrast, most pumping wells (except those with unusual completion styles, such as Y-block completions) cannot accommodate a production logging tool because the pumping apparatus prevents access of the logging tool to the underlying perforated interval.
• Ability to quantify uncertainty:  Geochemical techniques provide multiple, independent solutions to the allocation problem, allowing one to quantify accurately the uncertainty of an allocation result.  In contrast, the uncertainty associated with logging results is more difficult to quantify.
• No risk of sticking a logging tool: Because the geochemical approach relies only on produced oil samples, there is no risk of sticking a tool in the well.

Assessing the contribution of multiple fields to commingled pipeline production streams

• Ability to allocate in the absence of flow meter data:  Geochemical techniques can allocate commingled production at points in the production stream where flow meter data are unavailable.
• Ability to identify problems with flow meter data: Where flow meter data are available, geochemical data provide complementary information for allocating production, because geochemical techniques measure the relative contributions of oil (instead of water + oil) to a production stream.  Since geochemical production allocation cannot be impacted by entrained water, the geochemical techniques provide an independent check on allocation data from flow meters.

Methods

Allocation of commingled oil:  Methods for using oil compositional differences to allocate commingled production from a single well are detailed in Kaufman et al. (1987; 1990; 1997), McCaffrey et al.(1996), and Nicolle and Boibien (1997). Similar methods for allocating the contribution of multiple fields to commingled pipeline production streams are discussed by Hwang et al., (1999; 2000). These allocation techniques have been refined further by OilTracers, LLC.  In brief, production allocation is achieved by identifying chemical differences between "end-member" oils (samples of oil from each of the zones or production streams being commingled).  Parameters reflecting these compositional differences are then measured in the end-member oils and in the commingled oil. The data are then used to mathematically express the composition of the commingled oil in terms of contributions from the respective end-member oils.

Allocation of commingled gas:  Schoell et al. (1993) describe techniques for allocating gas production.  Gas allocation  is conceptually similar to oil allocation; the techniques differ primarily in the types of geochemical parameters measured, as discussed on our GasChem.com web page.

Background

The geochemical approach described here is based on the well-established proposition that oils from separate reservoirs tend to differ from one another in composition (e.g., Slentz, 1981; Kaufman et al., 1990; Hwang and Baskin, 1994; Hwang et al., 1994).  Depending on the field, these compositional differences exist for one or more of the following three reasons:

1. Processes that affect oil composition after oil enters a reservoir (e.g., processes such as biodegradation, water washing, and evaporative fractionation) do not operate to exactly the same extent in separate compartments.
2. Oil which a source rock generates at a given time differs slightly both from subsequently generated oil and previously generated oil due to continuous, subtle changes in the maturity of the source rock and changes in precisely which part of the source rock is in the oil window.  Since no two compartments are of identical geometry, and since no two compartments have exactly the same filling history, it is difficult to achieve precisely the same homogenized composition in two separate compartments - even with oil from the same source.
3. More than one source rock may contribute oil to an accumulation, and the oils from different sources differ in composition.  Since oils from different source rocks have different times of generation and/or different migration paths, the presence of more than one source may cause different compartments to fill with different mixes of oil from the respective sources.  For example, Prudhoe Bay oil is known to be a mixture of petroleum from three source rocks (Masterson et al., 1997 and 2001), and source variations are therefore a significant cause of the compositional differences in that field.

When oils from discrete zones are commingled, these chemical differences between the oils can be used to assess the contribution of each zone or each field to the commingled production.

Out-Dated (Obsolete) Method for Geochemically Allocating Commingled Production from Two Zones:

As described in the figure below, using a simple mixing model, a single geochemical difference between oils from two sands is sufficient to allocate commingled production from those two units (e.g., Kaufman et al., 1990):

Figure 1: This figure shows a previously published, now obsolete, method for quantitatively allocating 2 commingled zones. Oil samples from each zone (the "end members") are mixed in the laboratory. Analyses of these mixes and the pure end members allow construction of mixing calibration curves, such as those shown above. Each curve shows the values for one peak ratio (i.e., a ratio of two compounds observed in the oil) in different mixes of the oils. To assess the contribution of each zone to a commingled oil, gas chromatography data for these peak ratios in the commingled oil are simply plotted on the calibration curves (red symbols in this figure). To allocate a sample derived from two zones, only one calibration curve (one peak ratio) is needed. However, by using data for several peak ratios, independent solutions to the problem are derived, allowing the accuracy of the allocation to be assessed. This method, while easy to understand, actually has rather limited utility, because (1) it only can be used to allocate contributions from two zones and (2) it requires analysis of artificial mixes of the end member oils, since compound ratios do not necessarily mix linearly. At OilTracers LLC, we use a much more sophisticated method for geochemically allocating commingled production: our method can “unmix” contributions from an unlimited number of zones and can do this without making artificial mixes of the end member oils

At OilTracers LLC, we allocate production from multiple zones (two OR MORE zones) using OilUnmixer™ v 4.0, which is a proprietary software package developed and owned by OilTracers LLC. Our approach is completely different than that described in Figure 1 above. Instead of using compound ratios, our software is based on a more sophisticated version of the linear algebra method first published by McCaffrey et al (1996). That publication showed how the commingled production from several sands (or several fields) can be allocated to the discrete units using a linear algebra manipulation of the concentrations (not ratios) of several compounds in the end members and the commingled oils. Our software package (OilUnmixer™ v 4.0) is more sophisticated than the McCaffrey et al. (1996) approach in that our current software package utilizes more advanced methods for:

1. dealing with analytical uncertainty,
2. assessing the validity of end member (zone specific) calibration samples,
3. finding and mathematically removing contamination in the end members or commingled oils, and
4. "testing" the validity of the allocation results (in a graphical, easy to understand form).

This software package is available for licensing from OilTracers LLC. Results of the numerous blind tests of the OilUnmixer™ software are available.

For more information on the technique described here, or to discuss a specific project, e-mail us at info@oiltracers.com, or call us at (214) 584-9169.

References

Hwang R. J., Ahmed A. S. and Moldowan J. M. (1994). Oil composition variation and reservoir continuity: Unity Field, Sudan. Organic Geochemistry 21(2), 171-188.

Hwang R. J. and Baskin D. K. (1994). Reservoir connectivity and oil homogeneity in a large-scale reservoir. Middle East Petroleum Geoscience Geo 94 2, 529-541.

Hwang, R. J., D. K. Baskin, et al. (1999). Allocation of commingled pipeline oils to field production. Abstracts, 19th Internatisonal Meeting on Organic Geochemistry. Istanbul, Turkey, Tubitak Marmara Research Center Earth Sciences Research Institute. Vol. II: p. 602.

Hwang, R. J., D. K. Baskin, and S. C. Teerman, 2000, Allocation of commingled pipeline oils to field production: Org. Geochem., v.31, p. 1463-1474.

Kaufman, R. L., A. S. Ahmed, and W. B. Hempkins, 1987, A new technique for the analysis of commingled oils and its application to production allocation calculations, paper IPA 87-23/21: 16th Annual Indonesian Petro. Assoc., p. 247-268.

Kaufman R. L., Ahmed A. S. and Elsinger R. J. (1990). Gas Chromatography as a development and production tool for fingerprinting oils from individual reservoirs: applications in the Gulf of Mexico. In: Proceedings of the 9th Annual Research Conference of the Society of Economic Paleontologists and Mineralogists. (D. Schumaker and B. F. Perkins, Ed.), New Orleans. 263-282.

Kaufman, R. L., H. Dashti, C. S. Kabir, J. M. Pederson, M. S. Moon, R. Quttainah, and H. Al-Wael, 1997, Characterizing the greater Burgan Field: Use of geochemistry and oil fingerprinting: SPE Paper No. 37803, p. 385-394.

Masterson, W. D., L. I. P. Dzou, A. G. Holba, A. L. Fincannon, and L. Ellis, 2001, Evidence for biodegradation and evaporative fractionation in West Sak, Kuparuk, and Prudhoe Bay field areas, North Slope, Alaska: Org. Geochem., v. 32, p. 411-441.

Masterson, W. D., Holba A. G., and Dzou, L. I. P. (1997) Filling history of Americaús two largest oil fields: Prudhoe Bay and Kuparuk, North Slope Alaska. Abstracts of 1997 AAPG National Meeting, Dallas, TX.

McCaffrey, M. A., D. K. Baskin, M. A. Beeunas, and B. A. Patterson, 2006, Reducing the Cost of Production Allocation by 95% Using a Geochemical Technique: Abstract, AAPG 2006 Annual Convention, Houston, Texas, April 9-12, 2006.

McCaffrey M. A., Legarre H. A. and Johnson S. J. (1996). Using biomarkers to improve heavy oil reservoir management: An example from the Cymric field, Kern County, California. American Association of Petroleum Geologists Bulletin 80(6), 904-919.

Nicolle, G., C. Boibien, H. L. ten Haven, E. Tegelaar, and P. Chavagnac, 1997, Geochemistry: a powerful tool for reservoir monitoring: SPE Paper No. 37804, p. 395-401.

Schoell, M., P. D. Jenden, M. A. Beeunas, and D. D. Coleman, 1993, Isotope Analysis of Gases in Gas Field and Gas Storage Operations: Society of Petroleum Engineers #26171, p. 337-344.

Slentz L. W. (1981). Geochemistry of reservoir fluids as unique approach to optimum reservoir management. SPE #9582. Presented at Middle East Oil Technical Conference, Manama, Baharain.