By Geotrex Systems
Reservoir and production engineers depend critically on well production rates to carry out most of their basic everyday tasks. However, they seldom pay attention to the technical details of how these rates are determined in the field with respect to their quality, accuracy, currency and representativeness. This paper aims to point out why they should.
Worldwide, operators have sophisticated and well documented field operations philosophy and strategy. However important as the back-allocation problem is in operations, a metering philosophy is not included in that overall strategy. This paper also aims to point out why it should. Frequency, timing, back-up, redundancy, sparing etc should explicitly be specified and documented. More often than not however, operators merely follow the rigor of the regulatory authorities which casts doubt as to how the appellation ‘operator’ was earned in the first instance.
We begin with an examination of the pervasive but deeply flawed practice of intermittent well testing using test separators. Several authors have provided very good descriptions of the flaws of pursuing an intermittent metering philosophy and attendant escalation spike in field operations losses and costs. We do not aim to catalogue these references here since a copious inventory is provided in the appendices.
Rather we present a new ‘vista’ of problem ‘problems’ that may not excite the field metering technician but ought to be of interest to those charged with executing well and reservoir management strategies.
- Overarching focus on metering for fiscalization purposes. This widespread practice is not entirely surprising since short term cash generation depends critically of the metered volume of the primary product of the separation process. Unfortunately, not nearly as much attention is paid to metering for well and reservoir management purposes. Of the produced oil, gas and water as in the case of black oil field operation, only the produced oil rate is rigorously measured. Total gas produced may or may not be measured and in the case of the former not nearly with the same vigor or determination.
- Reservoir engineers ought to be alarmed that historically, produced water is rarely measured. Rather crude estimates are determined from random sampling of the well stream which may or not be representative unless special additional effort is invested in the use of auto samplers which aims to mix the flowing stream into a more homogeneous mixture suitable for sampling. Whether this is done or not, BS&W determination result is rarely instantaneously available leading to the additional difficulty of matching the value with the actual oil rate associated with it. This also means that direct comparison with MPFM water rate readings during a field test is near nigh impossible.
- Recently a number of operators have started installing direct water rate measuring devices on their production systems but these have been found to have BS&W range-dependent accuracies.
Some General Applications of Continuous Well Monitoring Technologies
- Proved Developed Producing Reserves Determination. One of the highest categories of reserves in the books is proved developed producing reserves (PDPR). By deploying a MPFM in CMM mode for 3, 6 or even 1-year, accurate oil, gas and water rates can be observed over time thus generating good quality data for use in high grade decline curve analysis (DCA and RTA analysis) from which proved developed producing reserves can easily extrapolated.
- Detection of changes in reservoir fluid PVT properties over time. According to Larry Dake, many reservoir engineers tend to work with the notion that once reservoir PVT properties are properly determined at initial conditions, they remain the same throughout the entire productive life of the reservoir. This is far from true.
- Proper Calculations of Royalties. The prevailing practice of calculating royalties using fiscalized well volumes is to the detriment of regulatory authorities. This practice makes royalty determination to be dependent on operator efficiency which shouldn’t be the case. Ideally, royalties should be based on well head volumes and MPFM systems deployed in CMM can assure accurate and representative wellhead volumes.
- Slug Control Systems. MPFM in CMM mode can assist slug control systems detect early the onslaught of slug flow and triggering the slug control mechanism. This is of critical importance in offshore platforms with risers of several kilometer rangers. Undetected onset of slug flow is one of the most-risky conditions in offshore oil operations.
- Gas Lift, ESP and other Assisted Lift Applications. MPFM in CMM mode can enable an operator to verify and validate or otherwise modify his gas lift design. Are gas lift valves placed at correct depths and are they opening at the correct pressures to deliver the correct volume of gas lift gas are some of the questions that could be answered.
- Optimized Chemical Injection Timings and Rates
- Matching Reservoir Simulation Time Steps. Most reservoir simulators run at a simulation time step of 1-day. However, producing well rates are often averaged weekly or over a month. What this means is that for input into reservoir simulators, the weekly or monthly rates have first to be approximately transformed into daily rates using actual days of production or calendar days. In either case, the projects’ quality is detracted from ab initio because of questionable back allocation issues based on unreliable intermittent test separator tests.
- Correcting laboratory determined fluid PVT properties for installed surface facilities conditions for use in material balance calculations.
- Surface Recombination Sampling; in what ratio should surface samples be recombined for purpose of generating valid and representative reservoir fluid for PVT properties determination.
- Similarly, by deploying a MPFM at an observation well and recording flow rates changes attendant to informed changes in surrounding wells, data can be generated providing useful information for determination of average drainage radius of development wells and consequently the optimal number of wells required for full reservoir development.
