The Defining of Gas Well Testing Fundamentals

 In the petroleum industry, a well test is the execution of a set of planned data acquisition activities. The acquired data is analyzed to broaden the knowledge and increase the understanding of the hydrocarbon properties therein and characteristics of the underground reservoir where the hydrocarbons are trapped.

The ability to analyze the performance and forecast the productivity of gas wells and to understand the behaviour of gas reservoirs with a reasonable degree of accuracy is of utmost importance in today’s natural gas industry. 

One of the most useful aids in analyzing gas well performance is the flowing well test. A complete analysis and understanding of the results of an appropriate well test enables one to determine the stabilized shut-in reservoir pressure, determine the rate at which a well will flow against a particular pipeline “back pressure,” predict the manner in which the flow rate will decrease with depletion and the resulting decline in reservoir pressure, and estimate the effective reservoir flow characteristics.

The results of well tests are often used by regulatory bodies in setting maximum gas withdrawal rates. They are also employed by producing and transporting companies in projecting gas well deliveries, in the preparation of field development programs, in the design of gathering and pipeline facilities, in the design of processing plants, and in the negotiation of gas sale contracts. Other important applications of well tests and of information gathered during testing are in the estimation of gas reserves associated with a well or group of wells and in making various types of special reservoir studies

Well Testing is the execution of the set of activities of planned data acquisition for broadening the understanding and knowledge of the properties of reservoirs containing hydrocarbons. It provides information about the state of a well. The main objective of Well Testing is to identify the capacity of reservoirs to produce hydrocarbons like natural gas and oil. The data gathered during Well Testing involves pressure and the volumetric flow rate observed in a particular well. Well Testing requires the right technology, planning and implementation in order to gather information about a particular well

Well Testing determines fluid properties, reservoir pressure, areal extent, flow rates, vertical layering, drawdown pressure, permeability, formation damage, productivity index and much more. The dynamic reservoir properties can be measured using a well test. It also allows the operators to extract fluid samples from the reservoirs in order to observe changes in the properties of the reservoir fluids and in the composition between the wellhead and the perforation. The information gathered is essential for the prediction of the reservoir and well completion. By measuring the flow rates and pressures physically, well testing offers large scale measurement of permeability.

Taking measurements while flowing fluids from the reservoir 

Well and formation tests, which entail taking measurements while flowing fluids from the reservoir, are conducted at all stages in the life of oil and gas fields, from exploration through development, production and injection. Operators perform these tests to determine whether a formation will produce, or continue to produce, hydrocarbons at a rate that gives a reasonable return on further investments. Operators also use test data to determine the limits of the reservoir and to plan the most efficient methods for producing wells and fields.

During testing, operators measure formation pressure, characterize the formation fluids and reservoir and determine permeability and skin—damage to the formation incurred during drilling or other well operations. Data that indicate how the formation reacts to pressure increases and decreases during a test can also reveal critical information about the reservoir.

Well and formation tests are also primary sources of critical data for reservoir models and are the principal means by which engineers confirm or adjust reservoir model parameters. Engineers use these models to understand how reservoir fluids, the formation and the well interact and use that knowledge to optimize completion and development strategies.

Operators assess the production potential of wells through several test methods, singularly or in combination. They may choose to perform a production well test in which the well is flowed through a temporary completion to a test separator. Or they may use a wireline formation tester to capture fluid samples and measure pressure downhole at the zone of interest. Engineers sometimes perform both types of tests.

During production well tests, technicians flow reservoir fluids to the surface through a drillstring or a drillstem test (DST) string. Packers isolate the zone to be tested while downhole, or surface equipment provides well control. The well is flowed at different rates through a choke valve that can be adjusted to control the flow rate precisely.

Reservoir fluids produced to the surface are sent directly to holding tanks until test operators determine that contaminants such as drilling fluids are eliminated, or at least minimized, from the flow stream. After cleanup, flow is redirected to a test separator where bulk fluids are divided into oil, gas and water, and any debris, such as sand and other material, is removed. The three fluid phases are measured and analyzed separately. Operators may opt to obtain additional reservoir and fluid flow data by simultaneously running production logging tools into the well on wireline. These tools measure the downhole flow rate and fluid composition and can indicate which zones are contributing to the total flow.

During well tests, reservoir fluids are produced to the separator at varying rates according to a predetermined schedule. These tests may take less than two days to evaluate a single well or months to evaluate reservoir extent. Test types include buildup, drawdown, falloff, injection and interference. For most tests, engineers permit a limited amount of fluid to flow from or into a formation. They then close the well and monitor pressures while the formation equilibrates.

Buildup tests are performed by shutting in the well after some period of flow to measure increase in bottomhole pressure. By contrast, for drawdown tests, engineers open the well after a specified shut-in period to observe bottomhole pressure decrease. During injection tests and falloff tests, fluid is injected into the formation, and bottomhole pressure, which increases as a result, is monitored. The well is then shut in and the ensuing decreasing bottomhole pressure is recorded. Interference tests record the pressure changes in adjacent wells when the test well pressure is changed. The time it takes for changes in the test well to affect pressure at the observation well gives engineers an indication of the size of the reservoir and flow communication within it.

Engineers analyze responses to pressure change schemes using pressure transient analysis, a technique based on the mathematical relationships between flow rate, pressure and time. The information from these analyses helps engineers determine the optimal completion interval, production potential and skin. They can also derive average permeability, degree of permeability heterogeneity and anisotropy, reservoir boundary shape and distance, and initial and average reservoir pressures.

Engineers use specific variations on well buildup and drawdown tests to evaluate gas wells. During a backpressure test, a well is flowed against a specified backpressure until its bottomhole pressure and surface pressures stabilize—an indication that flow is coming from the outer reaches of the drainage area. An isochronal test is a series of drawdowns and buildups. Pumping rates vary for each drawdown, while subsequent buildups continue until the well reaches its original shut-in pressure. A modified isochronal test—in which drawdown and buildup periods are of equal duration—may also be used.

Based on data from these tests, engineers are able to determine production potential, skin and absolute open flow, the theoretical rate at which the well would flow if backpressure on the sandface, or the borehole wall, were zero. Operators use  absolute open flow as the basis for calculations to determine the relationship between backpressure settings and flow rates of the well.

Rather than use well tests, operators may opt to evaluate their wells using wireline formation testers that include a quartz pressure gauge and a fluid sampling tool placed across a production interval. During these formation tests, reservoir fluids are pumped or flowed into the wireline formation tester through a probe inserted into the formation or between packers set above and below the sampling site.

The reservoir fluids, which may be contaminated with drilling fluid, are first flowed or pumped through flowlines in the tool into the wellbore while the contamination level decreases. Once engineers determine that the formation is delivering minimally contaminated reservoir fluids, they redirect flow to sample chambers within the tool. The chambers are retrieved to the surface and transported to laboratories for analysis.

Scientists also use downhole fluid analysis  to monitor the sampling process. Using optical spectroscopy, or the recorded light spectrum, engineers identify in real time the composition of fluids as they flow into the tool; this method also reveals critical data about the reservoir without waiting for laboratory tests to be completed. Additionally, the downhole fluid analysis measurements confirm that the sample is uncontaminated and eliminate uncertainties associated with fluid transport and laboratory reconstruction of in situ conditions necessary for fluid analysis. Technicians also use downhole fluid analysis data to identify gas/oil ratios, relative asphaltene content and water fraction in real time.

A variety of well and formation test schemes are performed throughout the stages in the life of a well or gas field. At the exploration stage, operators may use well tests to simulate production after a well is completed to establish production potential and reserves estimates. In addition, capturing large fluid samples at the surface gives experts an opportunity to perform laboratory measurements on the reservoir fluids.

Oil and Gas well productivity and deliverability

Well tests at the exploration stage also allow operators to determine if low flow rates are affected by skin or are the result of natural permeability of the reservoir. Armed with the knowledge of either situation, engineers can then take appropriate actions, plan treatments that may be necessary once production commences or decide to abandon the project for economic reasons. For instance, well tests can be used to estimate reservoir size, which allows operators to abandon a small reservoir that will not be economical despite high initial flow rates.

During the field development stage, well tests help indicate wells that may require stimulation treatments. Using well test data, engineers predict induced or natural fracture length and conductivity. They can then estimate productivity gains that may be realized from a stimulation treatment. In addition, wireline formation testers can be used for pressure testing to determine static reservoir pressures and to confirm fluid contacts and density gradients. This information helps analyze communication within the reservoir, tie reservoir characteristics to a geologic model and identify depleted zones.

During the production phase, well tests are aimed at monitoring reservoirs, collecting data for history matching—comparing actual production with predicted production from reservoir simulator—and assessing the need for stimulation. These tests use a pressure gauge placed at formation depth to collect data during pressure buildup and drawdown.

Well productivity usually diminishes over time, sometimes as a result of formation damage from fines migration—the movement of very small particles through the formation to the wellbore where they fill pore spaces and reduce permeability. Engineers may perform formation tests to predict the likely effectiveness of treatments to remove these fines. The effects of completion choices may also be assessed using formation tests to aid engineers in planning required remedial operations.