Uncertainties in Reserve Estimates

Estimates of oil and gas reserves are inherently uncertain. The extent and nature of commercially recoverable hydrocarbons from the subsurface cannot be determined with a high degree of precision. Recovery from subsurface reservoirs depends largely on the heterogeneities of the reservoir rock and the type of reservoir drive mechanism. Neither of these factors can be determined with a reasonable degree of certainty until after an accumulation has been developed and placed on production. Desorcy (1979) has discussed the source and probable magnitude of many of the errors associated with estimates of oil and gas reserves.

In addition to these physical uncertainties, there are commercial uncertainties. In the long run, oil and gas recovery is controlled by

· the costs to acquire exploration and development rights

· the costs to produce, treat, and transport oil and gas to market

· the market value of the volumes sold

Typically, these costs are incurred over a period of many years, with significant expenditures frequently being required a year or more before any income is realized.

The commercial environment — and the associated uncertainties-in which oil and gas reserves must be estimated is no less important than the physical environment. In today’s oil and gas industry the commercial environment may be subject to more uncertainty than the physical environment.

The range of uncertainty in estimates of reserves depends mainly on

· the degree of geologic complexity

· the maturity of the property

· the quality and quantity of geologic and engineering data

· the operating environment.

Geologic Complexity

The degree of geologic complexity in a group of properties may vary widely. At one extreme, the properties may be in an area of low structural relief, little or no faulting, no unconformities, and oil and gas reservoirs in the same general type of depositional unit (e.g., the lower Tuscaloosa (Cretaceous) trend in the southeastern USA). At the other extreme, the properties may be in an area of considerable structural relief, extensive faulting, numerous unconformities, and multiple depositional units (e.g., the North Sea).

Maturity

We can describe the maturity of an oil and gas property in terms of three stages of development and production:

· Geologic delineation/reservoir characterization, including

· discovery of the oil and gas accumulation and the period required for delineating the major geologic features controlling the extent of the accumulation

· determining the characteristics of the reservoir rock-fluid systems.

· Reservoir optimization, including the period of additional development, sustained production, and reservoir surveillance required for

· determining reservoir drive mechanisms and probable recovery efficiencies

· establishing optimum well spacing and production policy

· implementing improved recovery projects, if needed, to increase commercial recovery of oil and gas.

· Settled production, including the period during which wells have responded to fluid injection (if any) and have developed performance/production trends that may be analyzed to estimate reserves.

Quality and Quantity of Data

The minimum data necessary to estimate reserves with a reasonable degree of confidence vary widely from one property to the next and depend, in part, on the geology and maturity of the property. For a property that is monitored from its discovery and produces by primary reservoir drive mechanisms, acquisition of most or all of the following data is recommended:

· sufficient seismic data to identify and delineate major geologic features and probable reservoir limits

· sufficient subsurface control (wells) to delineate major structural and stratigraphic features, fluid contacts, and reservoir limits

· drillstem, wireline, or cased-hole formation tests on all zones not placed on production

· full-diameter cores in key wells in all major reservoirs

· sufficient wireline logs to identify all zones potentially productive of oil or gas and to characterize the lithology, net thickness, porosity, saturation, hydrocarbon type, and probable productivity of each zone

· sufficient sidewall samples to supplement full-diameter cores and help resolve log interpretation problems

· initial potential tests as each well completion is placed on production

· bottomhole transient pressure test on each well zone placed on production, preferably during the initial test period

· samples of reservoir fluids from all major reservoirs to define hydrocarbon fluid composition, saturation pressure, and other physical properties, with sufficient samples to ensure representative data and determine possible spatial variations in fluid properties;

· special core analysis data (depending on the nature of the reservoir rock-fluid system and drive mechanism), including water/gas, water/oil, or gas/oil relative permeability, capillary pressure data, pore volume compressibility versus net overburden pressure, etc.

· monthly production of oil, gas, and water, and production method for each well

· monthly potential tests on all wells

· sufficient historical bottomhole pressure data to determine reservoir drive mechanisms and to identify possible discontinuities between wells completed in the same reservoir

· historical data on all downhole remedial work, including stimulation, and same zone and new zone recompletions

· through-casing monitoring program (in multiple-zone fields) to detect possible drainage of behind-pipe zones, especially in water drive fields

· historical operating data, including revisions to downhole pumping and surface processing equipment that have affected the production rate of oil, gas, or water

· current sales prices and sufficient historical operating cost data to facilitate estimating average current and future costs

· costs to drill and complete wells, and to install treating and processing facilities

· operator’s plans (if any) to drill or work over wells or to modify, or augment, production equipment

· historical, current, or anticipated future restrictions on market conditions or processing or transportation facilities.

In reservoirs with improved recovery projects, this list should be expanded to include surveillance of monthly injected volumes and pressures from each injection well. Data requirements for improved recovery projects tend to be method and project specific. Talash (1988) has discussed data requirements for waterflood projects. The National Petroleum Council (1984) has published an extensive bibliography of papers on improved recovery methods which can provide insight into data requirements for such methods.

Operating Environment

The operating environment of an oil and gas property is one of the major factors controlling the costs of developing and operating the property. These costs, and the market price of the production, have a direct impact on the minimal size of a commercially exploitable accumulation and, thus, whether any portion of the accumulation may be classified as "reserves."

In the North Sea, for example, an accumulation containing 30 million barrels of oil in place was considered marginal (Home et al. 1988). It was a candidate for commercial exploitation only because it was near an existing production platform and could be produced from satellite facilities. In contrast, in West Texas — an area with an extensive infrastructure — accumulations less than one percent of that size are commercially exploitable.

Reserves Estimation: Material Balance Methods

Expanded Material Balance Equation

Principles

The so-called Schilthuis (1936) material balance equation is one of the fundamental relations in reservoir engineering. In "expanded" form, which includes water influx, it may be stated:
Production of oil and gas = Expansion of oil and gas initially in place + Water influx
Assuming an initial gas cap and — at this time — ignoring compressibility of pore volume and interstitial water, the equation may be written:

Np[Bt + Bg(Rp - Rsi)] + WpBw = N[(Bt - Bti) + mBti(Bg - Bgi)/Bgi] + We (1)

where the left-side terms account for the reservoir volume of oil, gas, and water production, and the right side terms account for the expansion of the oil and free gas initially in place, plus the water influx. (All notation in this section is SPE standard.)

Equation 1 is consistent with the formulation of Schilthuis, who ignored compressibility. However, compressibility effects should be considered for material balance calculations involving oil reservoirs above the bubble-point. Depending on the magnitude of rock-fluid compressibility compared to overall system compressibility, it may be desirable to include rock-fluid compressibility for oil material balance calculations below the bubble-point.

In Equation 1, it is assumed that the reservoir can be treated as a "tank," with spatial variations in PVT properties and reservoir pressure being averaged.

There are three unknowns in Equation 1:

· STB oil initially in place (N);
· size of the initial gas cap as a fraction of initial oil zone volume (m) ; and

· cumulative water influx (We).

In application, Equation 1 is solved at the end of successive time periods, generally quarterly, using the cumulative production data at the end of each period and PVT properties evaluated at the average static reservoir pressure at the end of the period. Theoretically, given enough pressure-production history and repetitive solutions of Equation 1, it should be possible to solve for all three unknowns. In practice, this is rarely possible, mainly because of errors in measuring, and problems in interpreting and averaging, bottomhole pressures. If both a significant initial gas cap and water influx are a possibility, efforts should be made to determine initial gas cap size using volumetric methods.
Limitations

Limitations to reliable application of the material balance equation are both theoretical and practical.

Theoretical limitations are imposed by assumptions necessary for a tractable methodology, which are

· The assumption that oil and free gas in the reservoir are in thermodynamic equilibrium. Wieland and Kennedy (1957) report about 20 psi supersaturation in experiments conducted using East Texas and Slaughter field cores.
· The assumption that the PVT data, obtained from differential liberation, replicates the liberation process in the field. As discussed by Dodson (1953) and others, both flash and differential liberation of gas may occur at various times and places between the reservoir and the stock tank, with the differences in PVT properties between the two processes increasing with more volatile oils.

· The assumption that free gas in the reservoir has the same composition as free gas on the surface, differing only in volume, as expressed by the gas formation volume factor. With progressively more volatile oils, free gas in the reservoir contains progressively more liquids in the vapor phase that are recovered as stock tank liquids but are not accounted for by the differential liberation process.

Practical limitations are imposed by data requirements and reservoir conditions. Data required for reliable application of the material balance equation include PVT analyses of representative fluid samples, accurate static bottomhole pressure history of key wells in the reservoir and accurate monthly production data for oil, gas, and water. The accuracy requirements usually exceed the routine needs for many field operations.
Reservoir conditions that may limit the reliability of a material balance estimate include:

· Strong water drive and/or a large gas cap which maintain reservoir pressure at nearly initial pressure. Under these conditions the material balance equation generally does not yield stable solutions, because the small pressure drops in the reservoir are frequently of the same magnitude as the errors in the measurements.
· A really extensive reservoirs with different areas at different stages of development and production. Generally, this leads to wide variations in gas saturation and reservoir pressure that cannot readily be "averaged."

· A really extensive reservoirs with low values of kh/m. These conditions make it difficult to determine the static bottom-hole pressure reliably and often cause large areal variations in pressure that are difficult to average.

· Very heterogeneous reservoirs with zones of high permeability interbedded with zones of low permeability, or highly fractured reservoirs. Under these conditions the lowpermeability zones, or the matrix blocks, usually pressure deplete more slowly than the high-permeability zones, or the fractures, and it is practically impossible to determine volumetrically weighted average reservoir pressure.

Some of these limitations may be overcome by using a multidimensional reservoir simulator, rather than a zero-dimensional material balance, or tank, model.
Irrespective of the material balance method used — tank model or multidimensional simulator — it is good practice to plot all of the bottomhole pressure data versus time on the same graph for all the wells suspected of being in a common reservoir. Such a plot usually provides valuable insight of the degree of communication between wells. It may help in identifying wells that are in separate reservoirs, contrary to the current geologic interpretation.

Reserves Estimation: Introduction

The term "reserves" means different things to different people. To the banker, reserves are the amount of capital retained to meet probable future demands. To the oil and gas operator, reserves are volumes of crude oil, natural gas, and associated products that can be recovered profitably in the future from subsurface reservoirs.

Reasons for Reserve Estimates

Estimates of oil and gas reserves are required for different purposes by different segments of the industry and at different stages in the life of a particular oil and gas property. Segments of the industry concerned with oil and gas reserves include

· companies and individuals responsible for exploration, development, and operation of oil and gas properties

· buyers and sellers of oil and gas properties

· banks and other financial institutions involved in the financing exploration, development, or purchase of oil and gas properties

· agencies with regulatory or taxation authority over oil and gas operators

· investors in oil and gas companies

Depending on the scope of their operation, operators of oil and gas properties require reserve estimates at various stages of exploration, development, and production. Of concern are

· potential reserves on undrilled prospects

· proved, probable, and possible reserves on prospects being developed

· sizing and design of equipment to process reserves and transport them to market

· opportunities for additional profit from incremental reserves that might be attributable to stimulation of producing wells, infill drilling, equipment modifications or additions or improved recovery projects.

Steps in a Simulation Study

There are five basic steps in conducting a reservoir simulation study:

· setting concrete objectives for the study
· selecting the proper simulation approach
· preparing the input data

planning the computer runs (including the order in which they occur)

· analyzing the results

Setting the Objectives
Setting objectives is the most important step in conducting a simulation study. Clearly defined objectives help us obtain the best information at the lowest cost and in the least amount of time. Improperly set objectives can take the study on a long, roundabout journey which leads to nowhere.

There are a number of factors that help us define appropriate objectives. The most important of these are data availability, the required level of detail, availability of technical support and available resources. In setting objectives , we use all of these factors to determine how to proceed. For example, it is unrealistic to attempt three-dimensional simulation when the available geological data gives no information about the presence and description of the various formation layers present in the reservoir.

In the broadest sense, when we consider all these factors, we will arrive at one of two types of objectives. These are sufficiently distinct that they affect the entire planning process of the simulation study. One type of objective is fact-finding, while the other is to establish an optimization strategy.

· Fact-finding involves answering questions about a system or process that is already in place. For example, a simulation study that matches well test data for the purpose of determining the damaged zone around a wellbore is a fact-finding mission.
· Optimization involves developing a number of plausible scenarios for a process (e.g., waterflooding) and studying the system response in an attempt to determine the optimum scenario. In this case,we must design a suite of numerical exercises, being careful to avoid waste on exercises that may not significantly contribute toward the goal.

Choosing the Simulation Approach
In choosing the simulation approach, we need to consider three basic factors:

· reservoir complexity
· fluid type

· scope of the study

While reservoir complexity and the scope of the study determine the simulator’s dimensions and coordinate geometry, the fluid type (together with the processes involved) dictate whether we should use a black-oil model or a more specialized model. For example, predicting well performance in a gas condensate reservoir will require a compositional rather than a black oil simulator. Furthermore, if the reservoir is thin and unlayered, it will be sufficient to use a one-dimensional radial flow geometry. Carrying out such a study with a three-dimensional compositional simulator will require additional computational resources whose added benefit cannot be justified. In any case, we must exercise our judgement and ingenuity in selecting the most appropriate simulation approach.

Preparing the Input Data

Because simulation studies usually require large volumes of information from a wide range of sources, preparing the input data can be a laborious task. However, the time spent in ensuring that data are properly prepared is worthwhile, in that it can prevent a great deal of headaches and waste later on in the study. Often, we discover data input errors only after a problem surfaces during the run, which wastes both time and computing resources.

It is our responsibility to ensure internal consistency in the data. Because data come from different sources, internal inconsistencies are not uncommon. We should resolve inconsistencies during the data input preparation. When data inconsistencies are present, they can lead to an ill-posed problem. Even worse, they could go undetected. With an ill-posed problem, we may be able to find the inconsistency by the failure of the simulator to run; but in the case of buried inconsistencies, the simulator may run and yield erroneous solutions.

Pre-processing capability, particularly for the commercial codes currently available, can facilitate data preparation. Sometimes these processors have internal checks to flag any detected inconsistencies in the data.

While data preparation is the simulation engineer’s job, input from other supporting personnel is extremely important. If inconsistencies appear in the data, or even if some data appear doubtful, it is imperative to resolve the problem with the help of the geologist, geophysicist and perhaps the production engineer. In summary, there is no overemphasizing the importance of adequate data preparation prior to making a simulation study. The payoff is exceptionally good.

Planning the Computer Runs

Planning computer runs is deceptively simple. To understand the necessity and the complexity of this planning, we only need to imagine a simulation study as a complex road map where the traveler knows the point of origin and the destination (these are clear enough from the objectives of the study). However, just as a traveler requires careful mapping out of the route that will get him or her to the destination in the best time possible, we must carefully map out the type and number of computer runs that will achieve the set objectives at a minimum cost. In so doing, we must account for several factors, which are usually problem dependent. We should consider the number of parameters to be examined, the duration of prediction, and the type of information needed to answer the pertinent questions.

Careful planning of computer runs includes not only determining their order, but also establishing a systematic labeling procedure for them. This is particularly important because of the large number of runs usually required and the voluminous amount of information invariably generated for analysis.

Analyzing the Results

When we have analyzed the results of the simulation study and made pertinent inferences from it, we can evaluate its success. This step caps all the efforts previously discussed. Considering the amount of effort that we expend on the simulation study up to this point, it is tempting to become a biased arbiter of the results. On the contrary, this is the time to ask critical questions and even ponder over the implications of the results. In other words, we must not become easy subscribers to our solutions.

The mode of analysis and the presentation of results will depend very largely on the audience for whom they are meant and the post-processing capability available. The graphics capabilities currently available on most computers makes this process easier and even more inviting. It is now not uncommon to display information using three-dimensional graphics. In addition, graphics features, such as image rotation and animation, enhance our interpretation and inferential ability.

Reservoir Engineering Data Sources

Several types of data are used in reservoir engineering calculations. The most important are

· data that pertain to the reservoir rock and its extent
· data that pertain to the properties of reservoir fluids
· production data

First we shall describe the four sources of data related to the reservoir rock and reservoir extent, which are
· geologic and seismic interpretations
· well log analyses
· well test analyses
· core analyses

Geologic and Seismic Interpretations
Reservoir geology helps the engineer to understand the external geometry of the reservoir as well as its internal architecture. Examples of the types of information it provides are

· the reservoir extent and its closure (the height of the crest above the lowest contour that completely closes the reservoir
· flow barriers, such as faults or pinchouts
· fluid contacts, (i.e., oil-water, oil-gas, and gas-water interfaces)
· aquifer size
· lithology variations
· continuity of the reservoir in the areal as well as in the vertical direction

Calculations from Well Logs
Logging provides in-situ information about the rock and its content from the immediate vicinity of the wellbore. There are over 30 types of logs, information from which may include:

· location of the productive stratum and its boundaries
· continuity of rock strata between adjacent wells
· net pay thickness
· oil, gas, and water saturations
· porosity of the reservoir rock
· other miscellaneous information, such as the condition of the hole, the temperature gradient in the wellbore, and the condition of the cement in a cased hole

Calculations from Well Tests
Well tests measure the pressure response of the well to short-term flow periods and the subsequent pressure buildup performance after shut-in. Various mathematical models can be used to determine the reservoir characteristics responsible for a particular pressure-flow rate behavior. In particular, permeability, the presence of nearby fault boundaries, or fluid contacts may be determined from an analysis of the well test data. Keep in mind that reservoir rock characteristics as determined from well tests are averaged values over the area of the reservoir that is contacted during the test.

Core Analyses

Cores provide petrophysical data essential to reservoir engineering. Basic core data, such as permeability, porosity, and fluid saturations help the engineer decide whether or not to complete the well and where to complete it. Special core analyses also help in evaluating reservoir performance, estimating hydrocarbons in place and reserves, evaluating the feasibility of EOR projects, and providing input data for reservoir simulation studies.

A second type of data used in reservoir engineering concerns the properties of the reservoir fluids and how they react to changes in pressure and temperature. Expressing the original hydrocarbons in place in surface volumes requires such data. Quantitative calculation of recoverable reserves requires estimates or laboratory determinations of formation volume factor, gas-oil ratio, and oil and gas compressibility, all as a function of pressure. Determining production rates of oil or gas requires knowledge of their respective viscosities at reservoir conditions. Any assessment of the practicality of EOR methods requires an understanding of the effects of the particular method employed on the behavior of the oil in the reservoir (i.e., oil viscosity reduction in a steam flood).

Reservoir fluid data is generally determined from a laboratory analysis performed on a carefully obtained representative sample of the original reservoir fluid. Where sampling is impossible, empirical correlations are available to estimate oil, gas, and water properties.

Production Data

This is another important type of data used in reservoir engineering calculations. By production data, we generally mean a careful accounting of the volumes of produced oil, gas, and water, as functions of time. Pressure as a function of time is also extremely important. The decline curve analysis and the material balance equation of oil or gas reservoirs require accurate production data in order to be of any value as predictive techniques.

The accuracy of production accounting can vary from field to field, particularly in large offshore developments where isolated wells and "satellite platforms" preclude the individual measurement of well production volumes on a regular basis. In such situations, individual well production is allocated from a total field production volume based on monthly well tests. In areas with high water-production rates the accuracy of measured water cuts also becomes a factor. Some estimate of the reliability of production data should be made by the engineer using such data in his or her calculations.

PRACTICAL ASPECTS OF WELL UNLOADING AND OPERATION

The guidelines in this section are adapted primarily from API RP 11 V5 (1999), Recommended Practice for Operations, Maintenance and Troubleshooting of Gas Lift Installations.

Initial Unloading

The first step in bringing a well on production after gas lift valves have been installed is to unload the fluids from the wellbore and obtain a stabilized production rate. Normally, a well placed on continuous gas lift is unloaded continuously, and a well placed on intermittent gas lift is unloaded intermittently. Primary considerations in unloading include avoiding excessive pressures that could damage the valves, and using clean, filtered workover fluids to avoid plugging or abrasion of the valves.

Prior to unloading, a two-pen pressure recorder should be installed at the surface to monitor both the gas injection pressure and the production (tubing) pressure. These pressures should be measured as close to the wellhead as practical. In any case, the gas injection pressure should be measured downstream of the injection choke, and the production pressure should be measured upstream of any flowline choke that is present. The wellhead pressure should be bled down to the pressure of the downstream separator, and the flowline choke, if present, should be either fully open or removed.

Continuous Gas Lift Wells

With continuous gas lift, the unloading process begins when gas is injected slowly into the annulus, probably through a choke located at the surface. Pressure is incrementally raised by approximately 50 psi every eight to ten minutes until it reaches about 400 psi, and 100 psi every eight to ten minutes thereafter. The kill fluid is displaced through the standing valve, up the tubing and to the surface into a disposal tank, until gas starts coming around the first valve or oil appears in the produced fluid. A steady stream of fluid will be then unloaded. If these fluids are directed into a separator, it is important to keep the backpressure on the well as low as possible. As gas is continuously injected into the annulus, a gradual increase in casing pressure will be required to keep fluids flowing from the tubing string.

Valve 1, the uppermost valve, is the first valve to be uncovered; gas first enters the tubing string at this point. This is noted at the surface by an immediate increase in the velocity of the fluid stream coming out of the tubing. A mixture of gas and liquid is soon produced at the surface, and the casing pressure levels off at the surface operating pressure of Valve 1. As gas continues to enter the annulus, the liquid column in the annulus is lowered until Valve 2 is uncovered. As soon as this valve is uncovered, gas flows through it and enters the tubing. Casing pressure then drops to the surface operating pressure of this valve. At about the same time, pressure in the annulus opposite Valve 1 should have been reduced to a level low enough to cause that valve to close.

Unloading continues from valve to valve until the deepest operating valve is uncovered. At this point, the bottomhole pressure has been reduced to a level that allows the formation fluid to move into the tubing, and the volume of gas injected through the operating valve is sufficient to lift the production under design conditions.

Intermittent Gas Lift Wells

With intermittent gas lift, fluid is unloaded at the surface in the form of piston-like slugs. The unloading process is the same as that for continuous flow until the uppermost valve (Valve 1) is uncovered. At that point, the well is placed on intermittent control for unloading. This is accomplished with a choke or a time-cycle controller at the surface so that the well is alternately produced and shut-in. During this period, the fluid in the annular space will continue to be U-tubed into the tubing and will be produced as slugs. A good cycle for unloading is obtained with 2 to 4 minutes of gas injection every 20 to 30 minutes. This allows ample time for stabilization to take place between slugs.

When the well is unloaded down to the operating valve, the choke size or cycle time should be adjusted to suit the well’s production characteristics. Thus the unloading operation may start with a high number of cycles per day and then, in response to the well’s production behavior, the number of cycles will be adjusted downward as fewer cycles will be needed to maintain optimum production rates. If the fluid production rate begins to fall off, then the number of daily cycles is too low for optimal production. With this information, it is possible to make further refinements to the process by reducing the duration of gas injection during each cycle. The objective is to maximize production and minimize the gas volume required. A very useful monitoring procedure involves simultaneously recording the shapes of the tubing and casing pressures curves. Adjustments are made on the basis of the shapes of these two curves.

System Adjustments

Once a well is unloaded, the next step is to optimize its production rate and gas usage. This will require some adjustment of its operating parameters. For detailed procedures, refer to API RP 11V5 (1999).

In a continuous gas lift installation, adjustments are generally made using an adjustable choke to control the rate of gas injection (a positive choke could also be used, but this would require interrupting gas injection to change the choke size). To prevent freezing, the gas system may be equipped with a dehydrator, gas heater or heat exchanger, or methanol may be injected upstream of the choke. To adjust the gas injection rate, the choke is initially set at a diameter that is larger than required for the design rate. The diameter is reduced incrementally until the production rate begins to drop, and then readjusted to establish the optimal production rate.

Similar types of adjustments are made for intermittent gas lift installations that employ time cycle control: the controller is initially set for a duration that will exceed the design gas injection requirements, and then the number of cycles per day is reduced until the well can no longer produce at its desired rate. The controller is then reset in steps until the optimal production and gas injection rates are established. For intermittent wells operating on choke control, the choke is initially sized for the design production rate, and then adjusted in the same type of trial-and-error manner.

Gas Lift System Monitoring

Successful gas lift performance depends largely on the efforts of field personnel. A gas lift installation requires close supervision during the unloading process, and when injection gas is adjusted and regulated.

A common practice is to analyze the system only when a problem arises. A better approach is to analyze each well while it is operating satisfactorily to determine if the installation has been properly designed. This provides a baseline measure of performance for reference in the event of trouble, and helps to indicate needed design changes. It is important to analyze this baseline information before planning well servicing or workover operations—otherwise, the operator will not know what changes are needed.

Diagnostic tools for monitoring and troubleshooting gas lift wells include:

Two-pen pressure recorder charts and calibrated pressure gauges installed at the well
Acoustical and production logging surveys
Fluid level determinations using wireline


API RP 11V5 (1999) describes these tools and their applications in detail.

Remote Monitoring

Gas lift wells are a common area of application for remote monitoring and control techniques. These systems can measure the performance of a single well or an entire field using sensors and data transmitting devices that alert field personnel to changes in well performance. By comparing performance parameters over time, the operator can analyze well stability, allocate lift gas injection, and optimize the operation of the entire field. This capability leads to improved efficiency, better field operations management, and increased profitability.

A significant feature of monitoring systems is their ability to remotely control gas injection and change well settings using two-way control devices. Continuous monitoring and comparison of parameters such as injection pressure, wellhead pressure, and flow rate lets the operator identify potential problems and take preventive and corrective action from a central location. In many cases, the operator is notified automatically when sensors detect significant changes to key parameters.

Primary components of remote monitoring systems include:

Downhole Pressure & Temperature Sensors
Sensor Data Process System
Well Controller
Remote Terminal Unit (RTU)


The downhole pressure and temperature sensors communicate via a system controller to adjust gas injection through the sensor data process system. This allows the operator to control the well or the field based on changing surface or downhole conditions.

A remote terminal unit (RTU) can transmit data continuously or store well performance data for later transmission and analysis. The RTU is a two-way system, thus allowing the operator to communicate back to the well.

The monitoring and communication equipment is powered by solar cells, which are backed up by a battery system to ensure a constant power supply.

Through monitoring of gas lift injection and production systems, field efficiency can be improved and future gas lift valve design, valve placement and unloading programs can be designed on the basis of actual field operating experience.

Material Balance Equation

Expansion, Production, and Influx Terms The material balance equation is an expression of the conservation of the mass of oil, gas, and water in the reservoir. The application of the conservation principle to the gas phase, for example, requires that the mass of gas in the reservoir at any time be equal to the mass of gas initially in place minus the mass of gas that has been produced.

Note: only the expansion of rock and its associated water in oil zone is considered.

where:
Np = cumulative oil production, STB
Bt = two-phase formation-volume factor, RB/STB
Rp = cumulative produced GOR, SCF/STB
Rsi = initial gas in solution, SCF/STB
Bg = gas formation-volume factor, RB/SCF
Bw = water formation-volume factor, RB/STB
Wp = total water produced in STB
N = initial oil in place, STB
Bti = initial two-phase formation-volume factor
m = ratio of gas cap pore volume to oil leg pore volume
Bgi = initial gas formation-volume factor
Swi = initial water saturation, fraction of pore volume
Sw = water saturation, fraction of pore volume
cr = rock compressibility, vol/vol/psi
cw = water compressibility, vol/vol/psi
Dp = pi - Pr(t)
pi= initial reservoir pressure, Psi
PR(t)= average reservoir pressure at the time of interest t, psi
We = cumulative water influx, RB

The two terms on the left-hand side indicate the total fluids production in reservoir volumes. The first three terms on the right-hand side are, respectively, the total expansion of the hydrocarbon in oil zone, the total expansion of the gas in gas cap, and the total expansion of the rock and its associated water. The last term is the water influx. Thus, a statement of the MBE which is simple and easy to remember is: total fluids produced in reservoir volumes equals total expansion of the hydrocarbon in the oil zone, the gas in the gas cap, and the rock and its associated water, plus the water influx in oil zone.

Compressibility of Rock and Water Terms
Normally one thinks of the water and rock as being incompressible. In fact, they are compressible. The rock compressibility is a function of its porosity and consolidation.

It can be as low as 3 l0-6 vol/vol/psi and higher than 20 l0-6 (Coats 1980). The water compressibility does not vary widely like the rock compressibility. It normally ranges between 3 and 6 l0-6 vol/vol/psi.
To illustrate the meaning of compressibility and the unit vol/ vol/Psi consider two cubic feet of water that are under pressure. Assume the Pressure is decreased by 10 Psi and the water compressibility is 3 10-6 per psi. Since the pressure decreases by 10 psi, the two cubic feet of water expand by 2 x 10 3 10-6 = 6 l0-5. The volume of water is now (2 + 6 10-5) cubic feet.

Advantages and Limitations of the MBE
The primary advantage of the material balance equation is that it provides a valuable insight into the behavior of the reservoir, and the contribution of the various drive mechanisms to recovery. In the case of reservoirs with reasonable reservoir-wide fluid communication, the MBE provides a method of calculating the initial oil or gas in place, as well as the expected aquifer effects, by using actual production and pressure data. The MBE is the only method that employs the dynamic response of the reservoir to production as a means of estimating the volume of original fluid. What the MBE calculates is the fluid volume in the reservoir that is affected by production.

The dynamic response of the reservoir fluid to production is manifested in the pressure change. Thus, the initial fluid in place calculated by the MBE is indicative of the fluid volume in communication with the wells. In contrast, the volumetric method of estimating the fluid in Place is a static method. It does not differentiate between connected and isolated areas. For this reason, the fluid in place calculated by the MBE cannot be larger than that calculated volumetrically, assuming an accurate volumetric estimate.

The main disadvantage of the MBE is that it is based on a tank model (i.e., a zero-dimensional model). Therefore, it deals with average values of rock and fluid properties for the whole reservoir. As a result, it cannot be used to calculate fluid or pressure distributions, nor can it be used to identify new well locations or the effect of well locations and production rates on recovery. The MBE cannot be used to predict water or gas channeling, and cannot account for the effect of heterogeneities on the behavior of the reservoir. When any of these factors is significant, reservoir simulation is required to predict precisely the behavior of the reservoir.