It is commonly known that when an oil well is first completed, the natural reservoir energy causes the fluid to flow to the surface for some period of time. However, most oil wells, at some point during their economic life, require artificial lift in order to increase the reservoir energy needed to raise fluid to the surface and obtain the maximum recovery of oil for maximum profit to the producer well. Artificial lift systems include rod pumping, gas lifting, hydraulic pumping, and centrifugal pumping. Continuous gas lift is the most commonly used artificial lift system in the oil industry. It is inherently a high volume method and the only one which makes use of the reservoir gas energy.
This paper discusses the use of a multiphase flow meter to optimize gas lift field operations. In particular, it will compare analysis methods for individual well’s performance using Multiphase Flow Meter versus Standard Nodal Analysis. This paper will also tackle GUPCO’s field experience of gas lift offshore operations.
The proper measurement of production in marginal fields and new developments to optimize gas lift operations is a very important factor in the oil industry. The enhanced allocation of gas lift wells can result in immediate production payback by increasing each well production versus the injection ratio through real time well data readings.
The changes in a well performance due to increased water cut led by its turn to changes in injection pressure required to efficiently lifting the well and also a decrease in the reservoir pressure or equipment malfunction. Hence, production optimization cannot be obtained because too much or too little gas is injected as the output of constant well performance changes and causes less well production rates.
Total production of a field can be increased, if it is properly managed with exact and accurate measurement of well performance using real-time data. The major challenges are associated with the optimization of gas lift well measurement and monitoring output through the use of multiphase flow technology.
Traditional well testing
The proper and accurate measurement of oil, water and gas in the production stream represents a critical reservoir management. Multiphase measurement using traditional methods creates several problems. First of all inaccuracies associated with the separation of production stream act as major deterrent in this measurement process. The second problem, which lies in the entrapment of phases within each other and also mathematics, shows that a complete phase separation cannot occur. With a multiphase flow meter, there is no separation, hence the oil is measured as it flows through the meter and instantaneously the readings appear on the monitor panel. Three phase separator measurements require costly maintenance schedules. The third problem of traditional separators is their large size and heavy weight. This problem is considered as a critical issue, specifically in offshore platforms or remote facilities, where space and weight are of major concern.
Multiphase flow meter
On the other hand, the Multiphase Flow Meters (MPFM) provides accurate, real time measurements of oil, water and gas flows simultaneously, without separation of the phase. The MPFM can be used in all flow patterns, having both oil and water continuous fluid streams. It requires no field calibration or prior knowledge of fluid properties.
Figure (1) shows the multiphase flow meter.Figure (1)
Multiphase measurement brings three fundamental advantages to oil companies and operators
Reduction in capital expenditure by eliminating test lines, separators and separate flow monitors. The meter also has size and weight advantages over test separators with the ability to perform all measurements through a un–manned process. All of which, represent sizeable investments for such locations as remote exploratory fields to transfer tankers.
More accurate well testing. By tying up well test result and comparing them to the measured shipped oil at the LACT unit, the overall production processes is hindered due to the comparison of old data or shipped oil .
Real-time well output measurement. This allows the tracking of each well’s dynamic production behavior, and results in real–time well optimization. This is especially evident in secondary recovery technologies such as gas–lift operations as well as diluents or injection wells.
Gas Lift Measurement Problems
The main problems associated with the optimization of Gas Lift Operations lie in the achievement of accurate measurement of small amounts of liquid (2–3%) in high gas (95-99.5%). Gas injected down hole reduces the density of the fluid and allows the low formation pressure to push up the lower density column. Gas compression incurs expensive capital and operational costs. If too much gas is injected into the well, the gas can possibly blow through the well and uneconomically lift a low amount of liquid. The amount of gas that the liquid column can hold depends on oil viscosity and surface tension, both of which very from well to well, depending on water cut. For example, if the mixture is water–continuous, the viscosity will be close to water, while a tight emulsion of 20-30% water can be extremely more viscous than the pure oil.
The second problem of gas lift measurement is the lift process itself. To properly optimize Gas–Lift operations, a measurement device is needed to accurately measure not only all three components but also to handle the common and irregular multiphase flow regimes that torment the traditional measurement process.
For many years, the industry standard for gas lift well optimization was based on nodal analysis using field-proven flowing pressure correlation for vertical and horizontal flow. In almost all cases, it has been impossible to accurately make the predicated model results match the reported well test data, or obtain a material balance for the field. This has occurred chiefly because of the inability to obtain accurate and repeatable well test results using standard testing methods. The time required to test and analyze an individual well was restricted, since the test separator is normally in use and dedicated to standard field operations. By using a multiphase flow meter, GUPCO’s engineers were able to obtain accurate real time data of well production and review the effects of changing the operating parameters of an individual well. By using the data acquired, not only were the operators able to achieve better results in individual well performance, but they were also able to approach a material balance for field production. The use of a multiphase flow meter allowed GUPCO to overcome the problems outlined above.
To use a multiphase flow meter for optimization, GUPCO had first to consider the required operating characteristics of such a meter. It needed a meter that would be accurate and easily transported between individual wells. This meter was also not to be affected by changes in fluid properties such as density or salinity. It was imperative to choose a meter capable of handling high gas volume fractions, as large as 99%, since gas lift wells fall under this category. It had also to accurately measure in all flow regimens, due to the fact that gas lift wells generally present the entire spectrum of flow regimes in pipes.
We will use a well that is 7,000 feet deep, has 3 inch tubing, a flowing size of 3 inches and 3,000 feet in length, a wellhead pressure of 80 psi and a P.I. of 5 bld/psi. The static reservoir pressure is 2600 psi. Typical performance relationship predications are shown in Figures 2 and 3. These examples show maximum flow rates with variable wellhead pressures for the given well. Moreover, they show the effects of injection gas volume on production. A decision can be made as to the desirable injection rate and resulting production rate based on field requirements from this data.
Figure 2 – Predicting Maximum Flow Rate – Variable Wellhead Pressure
Figure 3 – Predicting Maximum Flow Rate – Variable Wellhead Pressure
The limitation of such a method is that it requires us to assume consistent production rates all throughout the test period. The problem arises in applying such data, to data received from a typical two pen recorder chart. Figures 4 and 5 show such charts obtained from a well during the testing cycle. As seen on the charts, it is virtually impossible to make any accurate statement as to what the effects of actual rates may be on this given well. Let us compare that to the real time data obtained by the multiphase flow meter at the GUPCO facility (Figures 4, 5, and 6).
It can be seen that changes in the well performance can be observed immediately in real time. This allowed the operation engineers to make decisions in real time as to what changes were desired. It is also important to note that the real time data acquired was plotted and saved, and provided a well “signature”. Use of this signature is invaluable when comparing one test to a previous test. From now on, we will be able to notice a production problem in minutes rather than days, since any changes in that signature will reflect changes in the well performance. It is also imperative that we review the real time data as it relates to water cut and oil production.
Note how the water cut changes during the test. During a non-real time test, if we take water cut sample only once during the test, we may be very wrong in our projections. The only way to get accurate data is via real time. The data acquired from testing wells with the MPFM can be easily input into a spreadsheet. Doing this for each well and combining the data allowed us to develop a priority list based on Injection Gas wells based on the amount of oil produced for a given amount of gas injected. A list of this type is invaluable when it is necessary to shut wells in due to a loss of available gas lift gas volume. Without accurate well test data; we could very well compound our production losses due to shutting in the wrong wells. We would like to introduce some actual data obtained using the MPFM- in GUPCO’s field in Egypt. Overall test data in our standard report forms, no apparent problem was found. However, when reviewing the actual real time data we found obvious problems.
Well 1 shown in Figure 6 demonstrates a stable gas lift operation with production rates and injected gas rates appearing stable over the period of the test.
Figure 4 – Well #1
Now notice the real time data acquired from Well 2 (figure 5). This data indicated a serious problem with the well operation. Notice the severe heading in liquid production and gas injection. The conclusion was that the well either had a bad gas lift design, a mechanical failure of the gas lift valves, or communication between the casing and tubing. This problem is easily shown in our real Time data, but it would have been virtually impossible to find using only a standard test report.
Figure 5 – Well #2
Now notice the real-time data from Well 3 (figure 6), it shows that the well was logging up approximately every four hours. The indications were that there was a mechanical failure in the gas lift valve or poor spacing of the valves, which prohibited us from working down-hole to the lowest possible injection point. Additionally, we checked characteristics of the produced water to ensure that all water was from the producing formation.
Figure 6 – Well #3
The above examples illustrate the absolute need for real time data when attempting to optimize wells. This applies equally to wells producing naturally as well as those producing by gas lift or ESP pumps. Continuing the data application, we have found savings in injection gas, better well performance and the ability to develop a true priority list based on gas injection requirements. Equally as important, it is the ability of our reservoir engineering department to use the data acquired to analyze reservoir performance. GUPCO’s engineers now have the ability to do analysis of producing formations based on true accurate real time test data. Real time test data is imperative when conducting reviews of the reservoir’s performance and future capabilities.
The result is very accurate and comes from a multiphase flow meter that is light and compact enough to be placed on offshore platform. It can operate through a wide range of changing fluid Conditions. With the use of real time well data a production facility can accurately analyze individual well performance and use this data as a diagnostic tool for well maintenance and provide direct correlation between changing well activities for proper optimization.
Optimization of high gas by JO, Agar Corporation, SPE71477.
Field tests of high gas volume fraction multiphase meter by Perry, G. Shoup, SPE
Multiphase technologies for offshore production, by Dr. Abdelhady, Egas, Egypt
By: Dr. Atef A/Allah, Production General Manager, Egas