Engineer's Corner : DRC - Data Retrieval Corporation

The 4 key elements in Pressure Transient Testing using Surface Measurements

noreply@spidr.com — Mon, 21 Jun 2010 17:28:28 EDT

This is the first installment of a 4 part series outlining the 4 keys of pressure transient testing from surface measurements. Using surface pressure measurements for pressure transient testing applications is a technique that is under utilized in the industry today. Outside of Data Retrieval Corporation, which pioneered this technology in the 1980s, I dont believe there is another service company that is actively promoting and performing this work today. WHP to BHP conversion technology is often given little consideration because Petroleum Engineering textbooks declare that it is only possible under dry gas scenarios (defined as <10 BBLS/MMSCFD liquid) and therefore thought not possible when any appreciable quantity of liquids are being produced. A factor further complicating this technique is a lack of high quality surface measurement devices available in the oilfield marketplace today. This lack of gauge quality serves to introduce an additional error source into the WHP to BHP process, further eroding the confidence in this technology by Operating company engineers. We also commonly see other reasons for skepticism from reservoir engineers, such as: 1. Thermal decay (decline in surface pressure) effects during a Pressure Build-up (PBU) and the inability for any commercially available software to compensate for this phenomenon thus rendering, in their eyes, surface measurements invalid. 2. Surface pressure data tends to be noisier which can introduce additional challenges for analysis in conventional type curve matching software packages. 3. The perception that downhole gauges are always positioned at mid-perforation during the test. Our experience tells us that less than 1/3 of gauge deployments are to mid-perforation. The vast majority of downhole gauges are suspended in the production tubing at some distance above the reservoir, subjecting the downhole gauge to liquid fall-back/re-injection, phase change behavior and generally the same phenomena that the SPIDR system senses from surface. Performing Pressure Transient Testing from the surface holds distinct advantages over running wire and pressure gauges downhole, namely RISK and COST . If surface pressure measurements can be accurately converted to downhole conditions, there is NO VALID reason to not use surface measurements . SPIDR Surface Well Testing got its start in a geo-pressured environment (onshore, inlandwater and offshore) where wells are normally deviated and pressures and temperatures are elevated. These factors drove the operators to riskless and less expensive pressure transient testing options. It has also gained favor in HTHP environments around the world. Another area of interest is by those operators whose reservoirs produce sour gas, CO2 and / or H2S. The WELLBORE RISK along with the TOPSIDE (PERSONNEL/EQUIPMENT) RISK associated with running gauges downhole under these conditions are big drivers towards the use of our technology, not to mention the enormous cost savings that benefit our customers. If we start with these enormous advantages, we now are tasked with demonstrating the capabilities of this technology to match or closely track downhole pressure gauge results. In addition, when downhole gauges are routinely placed at some distance above the reservoir, it is even easier to demonstrate our distinct advantages. 1st Key Start with a High quality Surface Pressure Gauge . A surface pressure gauge that incorporates high resolution (0.01 psi or better) along with high frequency data gathering (1 sample per second or better) capabilities are the minimum requirements. High Quality means a Quartz type transducer; we would go a step further and specify a dual-quartz Quartzdyne transducer which is known as the best transducer provider in the Oilfield today. The Quartzdyne transducer provides the thermal stability and thermal compensation that is critical for pressure transient testing applications over a wide variety of wellbore conditions. Another key component of a surface gauge is how it will be installed on the wellhead. Is it directly installed (as an integral part) on the wellhead or is it attached to the wellhead via a capillary tubing system? These are subtle differences but can play a large role when it comes to accounting for changing temperatures, both at the wellhead and in the environment (daytime/nighttime). Is the gauge certified Intrinsically Safe? Is it reliable? How large is the memory and how long can it record data without changing batteries? Can data be downloaded during the course of a test without stopping and reprogramming? Is it easily installed on the wellhead in a matter of a few minutes? These are some of the key points to take away concerning the quality and characteristics of the surface pressure gauge you will want to use to gather the pressure data for pressure transient analysis purposes. The next installment will cover our 2nd key of pressure transient testing with surface measurements which is the importance of employing a robust WHP to BHP conversion algorithm.

Communication Testing For Observation Well Having a Liquid Column

noreply@spidr.com — Wed, 10 Mar 2010 10:32:08 EST

Figure one is a plot of the pressure response in an observation well having both a downhole gauge and a surface gauge. The observation well had a depth of 11,500 ft with a liquid level at 8,500 ft. An adjacent well was being stimulated and the operator was concerned with communication at the observation well. The operator simultaneously ran downhole and surface gauges to determine if future interference tests could rely on just the surface gauge. As can be seen in the attached Figure, the pressure data ( blue ) from the surface gauge is showing a +/- 5 psi night time/day time pressure response. Data from the downhole gauge ( red ) is showing a similar response but of smaller amplitude and with less "noise". The explanation for the observed pressure cycling is that the gas cap above the liquid column is expanding and contracting as the well head heats and cools from ambient temperature changes. There are three observations from the attached figure that require explanation; Why is the surface data noisier than the down hole data? Why is the amplitude of the day time/night time pressure swings greater in the surface gauge than in the downhole gauge? Over the course of observation period, why does the downhole gauge record a 51 psi decline while the surface gauge only declines 9 psi? The explanation for points 1 and 2 are related. The surface gauge is connected to the well head via a 20 ft long oil filled capillary tube that is 1/16" diameter (0.062 " i.d). When the ambient temperature changes, the oil in the capillary tube expands or contracts and the friction of the oil moving in the capillary tube is seen as increasing or decreasing pressure until the temperature stabilizes. This pressure response is magnified in cold weather as the oil becomes more viscous. In this example, the data was acquired in December! The extremely high resolution surface gauge is measuring the movement of the oil in the capillary tube which is seen as "noise" in the acquired data. This effect could have been minimized or eliminated had the capillary tube been purged of oil before the test. In contrast, the liquid and gas columns in the well are not only warmer than the oil in the capillary tube, they are also in a tubing string of very large diameter relative to the capillary tube connecting the surface gauge to the well. Had the capillary tube been dry, the magnitude of the day time/night time pressure swings would have been the same for both gauges. Future communication tests will employ "dry" capillary tubes. During the 6 day observation period of this communication test, the surface pressure declined 9 psi while the downhole pressure declined 51 psi. This is explained by the fact that the liquid column in the well bore was slowly re-injecting into the formation therefore changing the relative heights of the gas and liquid columns. When the downhole gauge was retrieved from the well, gradient stops were obtained that showed that the liquid gradient was 0.69 psi/ft. Dividing the 51 psi pressure change in the downhole gauge by the liquid gradient of .69 psi/ft shows that the liquid column decreased by 51psi/.69 psi/ft = 74 ft. This means that the gas column grew by 74 ft. Increasing volume of the gas at constant temperature means that the pressure must decline. The gradient survey showed that the gas column has a density of .13 psi/ft which when multiplied by the 74 ft drop in liquid levels, equals the observed decline of 9 psi in the well head gauge. In conclusion, neither gauge saw communication with the stimulation process, which was the objective of the test. Both gauges responded in identical fashion to both ambient and reservoir changes. The magnitude of the responses were different in this instance but had there been communication, the surface gauge would have detected the response as readily as the downhole gauge. This test demonstrates that communication testing can be done from the surface without the risks and expense associated with downhole gauges, regardless if there is a fluid level in the well. Figure 1

Input Sensitivity on DFIT Analysis

noreply@spidr.com — Wed, 10 Mar 2010 10:17:05 EST

The results of any computer model are only as good as the inputs. This is true in any professional field, and true for any model. At Data Retrieval Corp. we have been using our proprietary model for WHP to BHP conversion to conduct traditional PTA work for the past 25 years, with great success. However, as new resources are being developed with much lower permeability, traditional PTA tests are becoming less desirable due to the extremely long time required before any useful information is obtained. This has led to an increased number of diagnostic fracture injection or DFIT tests (Minifrac, MFO, Datafrac, mini pump-in etc.) being performed, and here at DRC we have seen a marked increase over the past year in the number of these tests where our SPIDR gauge is being used. Now that we are offering analysis of this data to our customers, for use in comparison to their own or the pumping companys analysis, we felt it important to illustrate that the results of these tests are sensitive to the inputs in much the same way as we see in traditional PTA testing. There are many inputs that go into a DFIT analysis, and we will focus on the ones utilized in Meyer & Associates MinFrac software. It is assumed the reader possesses basic knowledge on performing the analysis, and using the MinFrac or similar software. The basic analysis of the data, using various plots, is only sensitive to a couple inputs, and most of these should be well known. To start, using the Horner plot, we determine P* and the pore pressure gradient. Obviously these are only dependent upon the depth (TVD) and the specific gravity of the fluid used. Clearly, only specific gravity would likely have much room for error, and it is important to know exactly what fluid was pumped in so that the proper specific gravity is used. It is also important to use common sense here, and refer to drilling reports and other sources of information before just accepting what the computer calculates as reservoir pressure. If the reservoir pressure calculated is higher than what would have been balanced by the mud weight used to drill the well, and no connection gas or kicks were observed, then the P* calculation should be further scrutinized. Next, using regression analysis, we determine when closure happened, what ISIP at the surface is, what the surface closure pressure is, what bottom-hole ISIP and closure pressure is, the net pressure, stress gradient, and efficiency. Once again, really the only relevant inputs are the TVD depth and specific gravity of the fluid. The most important information obtained from this analysis is determining when closure happened, what ISIP is, if the well reached radial flow after closure, and what the most appropriate regression analysis is to use for the after closure analysis. After closure analysis is where reservoir pressure can also be calculated, but more importantly it is where formation permeability can be determined, and it is determined from the pressure response of the well during the infinite-acting time period. The formation permeability is very dependent on the total leak-off height (h or net pay, the total height penetrated by the leak-off) and the reservoir fluid viscosity. Most often the total leak-off height will be some value smaller than the total hydrocarbon pay thickness used to model production, or it may be equal to that thickness. The injection rates and other information can be used to more accurately model this input, but it is important to understand there is an inverse relationship between permeability and the total leak-off height. The software also provides information about the fracture using various computer models (simulations) such as the PKN, GDK, and Ellipsoidal models. Here, many more inputs (such as Youngs modulus, Poissons ratio, and fluid properties such as n and K) are taken into consideration to determine things like fracture half-length, fracture width, fracture net pressure, efficiency, and formation permeability. Table 1 below shows how a 5% change in any of the input values affects the values calculated by the computer models. In the table, the notation I stands for an inverse relationship, and D stands for a direct relationship. The TVD depth and specific gravity were not considered, as those values should be well known. Table 1) Sensitivity Analysis It can be seen in the table that correctly determining the leak-off height, fluid properties such as n, and the reservoir fluid pressure have the largest affect on the permeability of the formation as calculated by the computer models. The results of these DFIT tests (closure pressure, near wellbore effects, fracture dimensions, fluid efficiencies, and permeability) are used to determine if a larger fracture stimulation job should be done, and if so how to properly design it for maximum effectiveness. It is always important to be as thorough as possible when determining values to use as inputs for computer models in order to get the most reliable information out of the testing being performed. Data Retrieval Corp. has been in the well testing business for over 25 years, and we are happy to work with you on all your well testing needs, including DFIT testing. Our consultation in these matters is always free of charge.

Interference Testing: The Low Cost, No Risk Approach

noreply@spidr.com — Tue, 1 Dec 2009 16:39:12 EST

Interference testing, also known as a communication test, is a multiple well test that is used by operators to determine intra-field connectivity. Sometimes performed as a pulse test, an interference test is the concept of introducing a transient in one well, the active well, and monitoring the pressure on an adjacent well, known as the observation well. The active well is typically a producer or injector while the observation well is shut-in during the testing period. The transient introduced to the active well can be made by a variety of methods, but conceptually is made by changing the state of the well from producing to shut-in or the reverse. Also, a pressure pulse can be sent through the reservoir by pump-in or fracture stimulation. With pressure gauges on both the active and the observation well(s), a change in pressure response in the observation well is anticipated. In most cases, the main objective is to simply see whether or not there is communication between the two wells. Additionally, this technique is used to determine inter-well reservoir properties such as formation permeability and hydraulic diffusivity. In larger fields, multiple wells inter-connectivities are being determined; thus more than one observation well can be monitored for each active well allowing strategic testing and efficient use of down time. In the last several years hydraulic fracturing has taken strides with multi-well simul-fracs and horizontal, multi-stage fracturing. Many operators have seen or are concerned that an adjacent producer to a well to be fractured will be knocked offline by communication between the two wellbores during the fracture stimulation. In these cases, the fracture fluid is intruding on an adjacent well and waters out this adjacent producer artificially. An interference test can be used during the fracture job on candidate wells to see if and when each stage of the fracture is in communication with a neighboring producing well. For this interference test, the introduced transient is the pressure resulting from each fracture stage. These studies will allow operators to better understand the well spacing needed for future drills, the impact of interference and develop a pressure versus distance calculation based on the resultant transient. With this data a more efficient fracture schedule can be put in place for the field. Recently, an operator came to DRC with plans for pressure mapping their old oilfield for EOR. This is a typical testing procedure performed initially with water injection to be followed with CO2. While in secondary recovery, the injection wells can act as the active wells, while the producers will be the observation well. There were 3 test plans that the operator was considering: Have a field-wide shut in, restart injection on a chosen active injector and observe the pressure response of the shut in adjacent wells. Shut in only the adjacent wells to the online injector and then shut down the injection well. Pulsing the injector at a higher rate and pressure while the observation wells are shut in. These plans all produce the transient needed to obtain critical interwell properties and can be performed with only the aid of the SPIDR gauges and existing equipment. With the help of DRC engineers, the operator chose plan #2 where they could gather both the communication data as well as individual falloff data for the injector that is the active well in the test. With the data accumulated, the operator was able to determine the interwell permeabilities and prepared a cost-efficient CO2 injection program. Since the pressure change detected on the observation well can be very small (0.01-0.05 psi) over the distance the transient travels from the active well, a high resolution digital pressure gauge must be used. Conventionally, a downhole gauge run on slickline or wireline has been used for these types of tests. Interference tests require only the detection of a pressure response in the observation well due to the active wells induced transient, thus a high quality surface gauge with high resolution and sample rate can be used in place of the cost and risk intensive downhole gauge. The SPIDR gauge is the highest quality surface pressure gauge in the oilfield. No other gauge has higher resolution, faster sampling or better thermal compensation than the SPIDR. The SPIDR gauge records pressure at 0.01 psi resolution with its dual-quartz transducer. A dual-quartz transducer is a 2 crystal transducer, one to measure pressure and the other to thermally compensate the pressure crystal as ambient temperatures change. This, along with the out-of-line connection of the SPIDR to the wellhead, allows the SPIDR to accurately record wellhead pressure with minimal to no response due to changes in the surrounding temperature. The SPIDR can sample and store its high accuracy, high frequency pressure data for over 2 months without any disconnected data downloads, memory card swaps or any other data retrieval method that will cause a pressure acquisition interruption. There are many variations to the interference test. With each test, the common thread is the need for accurate pressure vs. time data acquisition. The SPIDR gauge offers a low cost, no risk approach to performing all the variations of interference testing. Whether looking to calculate interwell reservoir properties throughout a field or looking for the presence of communication between two wells, the SPIDR gauge allows detection of the smallest pressure change possible without wireline trucks or well intervention. The extended memory and high resolution of the SPIDR allows interference testing in tight reservoirs and shales. The SPIDR can be downloaded real-time without data collection interruption with the aid of a laptop so the most efficient test can be performed. If you have further questions about interference testing, the SPIDRs capabilities, or would like to inquire about DRCs free test planning, please give us a call or contact us via email. Ph: (281) 444-5398 Email: drc@spidr.com

Gauge Selection for Pressure Transient Testing

noreply@spidr.com — Tue, 1 Dec 2009 15:40:58 EST

Strain Gauge vs. Capacitance vs. Quartz When conducting transient tests (PTA) on high permeability reservoirs or for pre-frac injection fall off tests, the importance of pressure gauge quality cannot be overstated. There are three primary considerations in gauge selection: 1. resolution 2. sample rate 3. thermal response of the gauge. The three major classes of gauges used in PTA testing are strain gauges, quartz capacitance and quartz crystal gauges. Strain gauges are popular because of their very low costs compared to quartz gauges. The cost ratio can be greater than 10 to 1. Strain gauges are basically non-conductive surfaces or membranes onto which a conductive pattern has been applied. When pressure is applied to the surface opposite the conductive pattern, the conductive pattern is distorted or "strained" which causes its resistance to change. The change in resistance is proportional to the applied pressure. The simplicity of the system leads to its relatively low cost. However this type of gauge has low resolution (0.5 psi) and is difficult to compensate for changes in the temperature of the gauge elements. Additionally strain gauges are slow to respond and stabilize to pressure changes so the accompanying electronics are rarely capable of sampling at the 1 second sample rates that are essential for high permeability reservoirs and frac design. Quartz gauges utilize quartz as the active sensing element because it is the most nearly perfectly elastic material known. The technical definition of elastic is that for an applied stress or pressure, the quartz sensing element will always give the same distortion or strain. The stress/strain response is repeatable over an almost infinite number of cycles. There are two main classes of quartz gauges, the capacitance gauge which relies on the mechanical properties of quartz and the resonant gauge which relies on the electrical as well as the mechanical properties. Quartz Capacitance gauges utilize parallel plates with conductive surfaces. One of the surfaces is subject to external pressure which results in a reduction in the capacitive gap. The resultant capacitive change is converted into a frequency that is proportional to the pressure change. If the reactive plate is a fused quartz element with a conductive surface, the gauge will exhibit much better repeatability than the same design gauge with a simple metal reactive plate. Quartz capacitance gauges have much better resolution (0.1 psi) than strain gauges but are also difficult to thermally compensate. Quartz Crystal gauges, also called Quartz Resonators, are the most accurate electronic transducers and the best of them are classified as "Secondary Standards". A secondary standard can be used as a substitute for a high precision laboratory Dead-Weight Tester. The quartz crystal resonator will generate a frequency that is proportional to the applied force or pressure. Quartz crystal gauges can deliver 0.01 psi resolution and when built with dual quartz crystals can also provide the most effective temperature compensation of any class of pressure gauge. As the illustration shows, the dual crystal quartz gauge employs one quartz crystal to only sense pressure while the second quartz crystal only senses temperature. The two crystals are embedded in close proximity to one another the same module so that the temperature of the two crystals are nearly identical and change in unison. The temperature crystal output frequency is used to compensate for thermally induced changes in the pressure crystal output frequency. The design of the dual quartz crystal resonator gauge requires sophisticated electronics which contributes to the cost of the gauge but it also allows one second and faster sampling frequencies. When selecting a pressure gauge for a PTA test or pre-frac test, the cost of the gauge is only a fraction of the total cost of all other equipment required at the well site during the test. Even more important, the cost of incorrect interpretation of reservoir properties as a result of poor quality data can be catastrophic. Considering the consequences of poor quality data, it is logical to always select the dual quartz crystal gauge. However, it is important to always keep in mind that the suppliers of each class of gauge described above, can and do describe their gauges as quartz. If the strain gauge uses a quartz substrate as the non-conductive element in the sensor, the manufacturer describes his gauge as "quartz". If the capacitance gauge supplier utilizes a fused quartz substrate as the sensing element, they also describe their gauge as quartz. It is important to keep in mind that all "quartz" pressure gauges are not equivalent and that only the dual quartz crystal resonator satisfies the PTA test requirements of high permeability reservoirs or pre-frac injection tests.

Interpreting Pressure Transient Tests

noreply@spidr.com — Tue, 1 Dec 2009 15:23:51 EST

There is a lot of information present in a pressure transient test, and it is the reservoir engineers job to correctly interpret that information in order to make the proper decisions regarding the production of the well being tested. One of the most useful plots that one can make from a pressure transient test is the pressure derivative plot. From this plot one can get an idea of the amount of skin damage around the wellbore, reservoir permeability, the reservoir geometry, and if there are any limits or boundaries nearby. Additionally, most commercially available analysis software utilizes Derivative Type Curve matching for pressure transient analysis. At Data Retrieval Corporation we test several hundred wells every year, and as such have seen a wide variety of datasets illustrating different reservoir behavior. In this article, we will present a few of these derivative plots to show the valuable information that can be obtained through well testing. It is also important to note that all of these tests were conducted from surface. The first example, which is the most basic plot, is of infinite-acting radial flow, as shown in Figure 1. Figure 1) Infinite-Acting Radial Flow As can be seen in the plot, the slope is zero during radial flow. During this time there are no effects seen from boundaries of any kind, and essentially the reservoir is seen as infinite in size. The permeability is determined from this plot. Also, the amount of skin damage can be inferred from this plot, as the amount of separation between the two curves is directly related to the amount of skin damage. The next example shows a type of limit contact where the well exhibits channel behavior during the pressure transient test. This can be seen in Figure 2 and Figure 3 below. Figure 2) Channel Behavior Figure 3) Channel Behavior on a Square Root of Time plot Channel behavior, which is linear flow between two parallel boundaries, shows up on the derivative plot as a half slope sometime after radial flow. The width of the channel can also be interpreted from this plot, as the distance between the two curves during channel behavior is directly related to the width of the channel. Additionally, during channel behavior a linear plot of the pressure against the square root of shut-in time will yield a straight line, as shown in Figure 3. Horizontal wells also have their own unique signature to pressure transient tests. Figure 4 below shows a derivative plot from a horizontal well. Figure 4) Horizontal Well There is a lot of valuable information about the horizontal well available from this pressure transient test. During the early (vertical) radial flow (ERF) the vertical permeability (kz) (around the wellbore) and skin damage around the wellbore can be determined. Here, the length of the horizontal section should be used in place of the net pay as used in traditional pressure transient analysis. During the pseudo (horizontal) radial flow (PRF) the horizontal permeability (kxky) (along the wellbore) and effective skin can be determined. Here, the true vertical net pay should be used. One issue commonly seen on wells making a considerable amount of water is liquid re-injection after the well has been shut-in. An example of this is presented below in Figure 5 and Figure 6. The Semilog plot is also shown to aid in illustrating when liquid re-injection ends. Figure 5) Liquid Re-injection Derivative Figure 6) Liquid Re-injection Semilog When testing from surface, it is important that the well be flowing at a high enough rate to bring all produced fluids to the surface naturally. Liquid re-injection occurs when a well is shut-in, and the water which before was being carried out of the wellbore falls back to the perforations, and is then re-injected back into the formation as pressure increases. During this time of re-injection, the reservoir response is being masked at the surface, and as such it is important to only do an analysis on the data after the re-injection is finished. It is also important to note that downhole gauges can also be subject to liquid re-injection issues as they are often set some distance above the perforations. Once the liquid level drops below the gauge, the reservoir response is masked until the liquid is fully re-injected. The final example shows wellbore storage during a pressure transient test, as seen in Figure 7 below. Figure 7) Wellbore Storage Wellbore storage shows up as a unit slope during the start of the pressure transient test. The longer wellbore storage lasts, the farther along in the plot the unit slope extends before breaking over and going into radial flow. Wellbore storage is the after-flow of fluids into the wellbore after the well is shut-in at the wellhead. During wellbore storage, reservoir effects are masked or distorted. Wellbore storage effects last until pressure is equalized between the well bore and formation. It is a common and incorrect belief that only surface testing is subject to wellbore storage concerns. In fact, downhole gauges are just as subject to wellbore storage effects as a surface gauge. The only way to minimize wellbore storage is by shutting in downhole. Data Retrieval Corporation has been conducting several hundred well tests every year for the past 25 years. We have seen a wide variety of test data, and have a large knowledge base in regards to well test planning and test analysis, in addition to our ability to accurately convert surface pressures to bottom-hole conditions. Please contact us in the future with any test planning or interpreting questions you may have. Our consultation in these matters is always free of charge.

Benefits of Conducting a Pressure Drawdown Test

noreply@spidr.com — Tue, 1 Sep 2009 08:56:19 EDT

There are many reasons to test a well. At DRC the most common type of test we see is the Pressure Build-Up. It is easy to conduct as it simply requires shutting the well in from stable flow. However, it requires the well to be shut-in which results in lost revenue to the operator. Low permeability wells require a long time to test which exacerbates the loss of revenue concern. To avoid the loss of revenue concerns, many operators have turned to the Pressure Drawdown Test to obtain their critical reservoir properties. A Pressure Drawdown Test is simply measuring the change in BHP during a period of production on a constant choke setting ( not constant rate). A well may decline in rate on a fixed choke, which is natural and can be accounted for in the analysis. Changing the choke to maintain a constant rate introduces extra transients which can interfere with the test interpretation. Usually the Pressure Drawdown Test begins with the well in a shut-in state, however it may also be conducted by greatly increasing (doubling) the current rate. The obvious benefit here is that the well is being tested and produced at the same time. This allows uninterrupted cash flow while simultaneously providing the engineer with information on the reservoir such as permeability, skin, and reservoir size. New wells are ideal candidates for drawdown testing as they are already in a shut-in state with uniform reservoir pressure. This early data obtained when bringing the well online for the first time can prove invaluable later in the life of the well. A well which has been shut-in for a long period of time for a workover or recompletion presents a good opportunity to conduct a drawdown test. In the event of planned maintenance where the shut-in is scheduled, the drawdown test may even be coupled with a build-up test. This can help eliminate any uncertainties in the interpretation of the data from the tests. A drawdown is less subject to phase re-segregation, cross flow problems, and thermal effects in the tubing compared to a build-up. If there is multi-phase flow in the reservoir or if the rock is highly compressive then a drawdown test can yield more reliable results than a build-up. Boundary/reservoir-limit testing is also typically done with the drawdown test. Also, reservoir dimensioning can take a long time, on the order of weeks or even months to see all limits, making a build-up test impractical; therefore these tests are typically done by performing an extended drawdown.

Wells in Tighter Formations Can Be Tested for Boundaries

noreply@spidr.com — Thu, 27 Aug 2009 11:30:45 EDT

DRC and WAVEX, Inc . teamed up to save drilling an unnecessary well for a South Texas Operator. We often hear from clients that it is not practical to test wells in areas that have tighter formations. While it takes a bit longer to test wells with permeabilities in the 1 to 2 Md. range the results are as accurate as in higher permeability formations. The time to test a given distance is a function of the square root of hydraulic diffusivity. Porosity, fluid viscosity, and compressibility are contributors along with permeability. WAVEX (wave exploration) is a patented process based upon a radial capillary and wave mechanics model. The method recognizes boundary contacts as discrete events in the data set. These events when placed into a general energy model produce information about individual reservoir boundaries. These boundary images are then assembled into a most probable map. This map is produced solely from pressure, fluid and log information without reference to the clients geologic map. WAVEX Energy Maps are relative images; that is, the direction of the boundaries with respect to north and south are not known. When the image overlays the geologic map, this is a completely independent confirmation of the geologic mapping. As a bonus, the method measures gas inplace much like a transient P/z. The hurdle is to deal with the time required to acquire the desired result. In this case the operator was concerned about the necessity of drilling a second well to drain the reservoir. Generally speaking, if we can see and map the reservoir, the operator can effectively drain the reservoir. Often in deep hot areas it is difficult to produce clear seismic images. The test required less than 30 days to execute as can be seen in the data plot below. The surface data was accurately converted by DRC to downhole conditions. The data set shows four clear-cut contacts, which were used in the WAVEX Energy Model to produce the following image of the reservoir. The next image is an overlay of the WAVEX Energy Map on top of the Seismic Map. Both are derived from different sets of wave mechanics yet the similarity of the overlay of the energy map to the seismic map is striking. The questions most often asked are Can you test a well accurately from the surface? and Can you produce a blind reservoir image from pressure data? The answer is we just did! Summary No new well was drilled due to a determination of effective drainage from the single well. The entire process involves a 30-day SPIDR Rental and a WAVEX analysis. The sum total cost is less that the price of a spinner survey. In this process it is not necessary to run a tool string into the hole. Keep in mind that test planning is free. If you would like to learn more about WAVEX please contact us at drc@spidr.com or Dr. Fred Goldsberry at wavex@sbcglobal.net .

Gauge Quality Will Affect Analysis

noreply@spidr.com — Thu, 27 Aug 2009 10:46:49 EDT

In the past two decades there have been major technological improvements in the field of pressure measurement. These improvements have been especially evident in the oilfield, which is the driving force behind most of these advances. When DRC was founded in 1985 most operators were using mechanical style pressure gauges (strain gauges) to capture both wellhead and downhole pressure data. As new technology became available most operators and service companies moved away from these simple mechanical gauges to ones that used strain gauges or quartz crystals. These new transducers yielded a much higher accuracy and resolution. One downside of the accuracy gained by using electronic transducers is that they are very sensitive to ambient temperature effects. These pressure transducers are so sensitive that the pressure they measure will be directly affected by ambient temperature changes on the electronics. For low quality gauges this may result in a one PSI change in pressure reading for every 1 degree Fahrenheit change in temperature. These types of effects will be seen not only at surface, but also by downhole pressure gauges. Downhole temperatures will change dramatically any time a well goes from flowing to shut-in. This change may have a serious effect on the pressure data being recorded downhole. The plot below shows an example of a pressure build-up data set that was provided to DRC to be used for analysis. This data was collected using a silicon on sapphire pressure gauge. It can clearly be seen that the temperature fluctuation from day to night is affecting the pressure readings. This effect on the data is even more evident in the derivative plot below. This data can still be used for basic analysis using semi-log plots. Any attempt to try to use this data for more advanced derivative type analysis will cause most pressure transient analysis (PTA) software to fail. This will be especially true if the goal of your test is to look for limits or other late time derivative behavior that will be masked by the pressure fluctuations. The SPIDR employs a dual-quartz pressure transducer. Quartz crystal transducers are currently the highest quality available in the industry. As the name suggests, the dual-quartz transducer employs two quartz crystal transducers. One transducer reads pressure while the other transducer reads the internal temperature. The pressure data read by the transducer can then be compensated for the current temperature. This allows the SPIDR to record very accurate pressure data without worrying about the effects of day to night temperature swings. The linear and derivative plots below show actual SPIDR data over a 30 day period. It can be seen from the derivative that the SPIDR data experience no day to night pressure fluctuations. If your goal in gathering surface pressure data is to simply watch the general trend over a long period of time, then most any type of pressure gauge will suffice. If you wish to use wellhead pressure data to perform pressure transient analysis you will need to take into consideration the type of transducer and the quality of the gauge itself.

Analysis Discrepancies when using PTA Software

noreply@spidr.com — Tue, 19 May 2009 08:29:23 EDT

Data Retrieval Corporation has built its reputation over the past 25 years by not only providing a cost effective, no risk method to capture high resolution, high accuracy wellhead pressure data, but by also then accurately converting this data to bottom hole conditions for an increasingly wide variety of gas and gas condensate wells. DRCs proprietary method for this conversion is what makes us an industry leader in surface well testing. However, in addition to the capture and conversion of the wellhead pressure data, DRC provides a complimentary analysis on the data (build-up, drawdown, two-rate, etc). The analysis method employed by DRC is the MDH Semilog analysis, an analysis method that may be different than what may commonly be done by operators today such as derivative type-curve matching using commercially available Pressure Transient Analysis Software (PTA Software). One of the reasons for this is that surface data often results in noisier derivative plots, which makes derivative type-curve matching more difficult. Another reason is that DRC rarely has all of the information about a reservoir that needs to be put into derivative type-curve matching software which would also make the analysis less accurate, and can cause the derivative plots generated by DRC and the PTA analysis software to differ. Analysis of the data based on these plots is then also subject to an individuals interpretation of the data, which allows for further discrepancies. Because of these differences, it is not uncommon for an operator to derive a different analysis of the data than what is provided by DRC. This is especially important when running a comparison against a downhole gauge, because it can then appear that there is an error in the conversion, when in fact this is not the case. It is important to make sure that the data is being loaded into the PTA analysis software properly, that the flow periods are properly accounted for, and that the appropriate plots are being generated for comparison purposes. DRC provides the most accurate conversion of wellhead pressure to bottom hole conditions available. Instead of comparing DRCs analysis with an analysis done on downhole gauge data using a completely different analysis technique by a different person, it is important to compare the actual pressure data. If the converted data matches well with the recorded downhole data, then an analysis should be done on both by the same person using the same analysis software and technique, so that the analyses can be compared on an apples to apples basis. When this is done, it is seen that the converted data provided by DRC allows for the same reservoir characteristics to be determined as by the downhole gauge. DRCs proprietary conversion algorithm remains unmatched in the industry today, and allows for a wide range of well types to be tested from the surface. DRC continues to offer a free trial to new customers in order to prove the technology, where a SPIDR and conversion of the data captured will be provided for free during a test in which a downhole gauge is also ran, provided DRC is provided the downhole gauge data after the report is completed. When this data is properly compared, and the analyses are properly done and then compared, it is seen that DRC offers downhole gauge results without most of the cost and none of the risk of going downhole.

Comparison of SPIDR vs DHG in High CO2 well

noreply@spidr.com — Tue, 3 Feb 2009 11:31:17 EST

Viability of surface testing for wells with high concentrations of CO2 in the wellbore. Performing pressure transient analysis tests from the surface provides a no risk and low cost alternative to traditional down-hole testing. However, this relies on being able to accurately convert the surface pressure to bottom-hole conditions. Data Retrieval Corp. has built its reputation by conducting hundreds of comparison tests with down-hole gauges over its 25 year history. In doing so, DRC has been able to greatly expand the number of wells that are testable from the surface. In the past, wells with high concentrations of CO2 would have been deemed poor candidates for surface testing, due to the difficulties in modeling the phase behavior of CO2. However recent opportunities to run tests in wells with high CO2 concentrations in conjunction with down-hole gauges have lead to advancements in our models that allow surface testing of wells with much higher concentrations of CO2. One such well presented here will show that surface testing is a viable option for wells with almost 32% CO2. The main difficulty associated with high CO2 wells is the unique phase behavior of the CO2. Proper modeling of wellbore conditions during flowing and shut-in periods is of utmost importance due to the extreme temperature and pressure sensitivity of the CO2. This is especially true during unstable flow periods, or when going from flowing to shut-in conditions as temperatures and pressures are changing most rapidly at those times. It is not uncommon for the CO2 to go through multiple phase changes in the wellbore. In the past this has prevented high CO2 wells from being tested from the surface. Conducting these comparison tests in conjunction with down-hole gauges has allowed DRC to improve our models to handle the difficult phase behavior of the CO2 and how its density rapidly changes during unstable or rapidly changing flow. Proper thermal modeling is also especially critical during the shut-in because improper modeling of the wellhead temperature would result in a build-up curve that is distorted, which would lead to an incorrect analysis. The cooling of the wellhead upon shut-in is a phenomenon known as thermal decay. When a well is shut-in, the heat being brought to surface by the produced fluids is cut-off. This results in cooling at the wellhead, which causes the density of the fluids to increase. This is sometimes seen as decreasing pressure at the wellhead during the build-up. DRC has developed a proprietary model for this phenomenon that accurately models the changing wellhead temperature and thus accounts for the increasing density. By employing DRCs proprietary model for thermal decay, accurate build-up pressures are calculated, resulting in correct build-up curves and analyses. Figure 1. Cartesian Comparison Plot of DHG vs SPIDR The well being presented makes 10-15 MMSCF/D gas and has a CO2 concentration just less than 32 mol%. It can be seen in Figure 1 that the SPIDR calculated bottom-hole pressure matches up very well with the three down-hole pressure gauges. There is a difference of about 15 psi during the build-up and about 25 psi during the flowing period. It is important to note that the flowing period was of a fairly short duration, and thus the well wasnt able to reach thermal stability, making it more difficult to model from surface. Figure 2 presents a semilog comparison plot of the build-up data and shows that the shape of the build-up curves also match up very well. This conversion was done blindly, or without the down-hole gauge data, and as such the first pass at modeling the thermal decay would require a bit of fine-tuning to generate results that perfectly overlay the with the down-hole gauge data. However, even without further adjusting the models, it can be seen in Table 1 that the reservoir characteristics determined from the SPIDR data very closely match those determined from the three separate down-hole gauge datasets. While the numbers are not an exact match, they are close enough to allow the operator to make the same decisions about their reservoir as the down-hole gauge results would. By taking these results and further fine-tuning the conversion models, DRC will be able to provide a viable alternative to running down-hole gauges for all the wells in this field. Figure 2. Semilog Comparison Plot of DHG vs SPIDR Table 1. Analysis Comparison of DHG vs SPIDR Pressure transient testing from the surface is a viable alternative to traditional down-hole gauge testing for an increasingly larger number of wells. DRC continues to push the limits of what is deemed testable from surface, and comparisons with down-hole gauges on wells such as this allow us to take the limits even farther. By continually advancing our models to account for higher concentrations of CO2 we present a unique opportunity to an increased number of operators to conduct pressure transient tests in the most safe, cost effective manner available on the market today.

Reservoir Dimensioning using the SPIDR

noreply@spidr.com — Tue, 3 Feb 2009 09:36:49 EST

Operating oil and gas properties in the Gulf of Mexico can present many challenges on a daily basis. Throw in an occasional storm or two and those challenges become more apparent. One company forced to shut in their wells due to a storm had an idea to take advantage of the upcoming shut-ins to perform much needed testing on a few of their more prolific wells. Data Retrieval Corporation had a proposal for such an occurrence. The proposal for one specific high rate producer called for sending a unit out for 30 days. During the 30 day period, if no shut-in of sufficient length for analysis occurred, the only cost to the operator would be shipping. A unit was shipped in hopes of obtaining a shut-in for evaluation of reservoir limits, boundaries, and faults. Based on reservoir seismic data, an offset drilling prospect existed which suggested the possibility of a separate undrained area. Since the prospect was downdip of the producing well, a high geologic risk was associated with the new prospect. It was hoped that the pressure data would either mitigate the risk, or deem another take point unnecessary. Through careful planning, a test was designed to either prove or disprove the possibility of drilling another well. Considering the cost to drill, it was very important to capture quality data for analysis. Along with DRC and the SPIDR, Wavex Reservoir Dimensioning and Imaging was brought in to interpret the gathered data and provide an independent geologic model to compare with the seismic mapping. About 2-1/2 months of accurate pressure data was obtained during the peak hurricane season of 2008, which involved several shut-in periods of varying duration. Wavex and DRC met with the operator to go over the data. Whats most interesting is the maps were made blindly, meaning no prior knowledge of what the operating companys maps looked like. To their complete satisfaction, the pressure data derived map was very similar to the geoscientists map of the reservoir, meaning that the two potentially separate areas were actually connected. Also, the reserves estimates given by Wavex closely matched what they had themselves reported. The end result of the data gathering and analysis was that no further consideration was given to a prospect which would have resulted in an expensive and unnecessary well. The operator involved was pleased with the results, that in the future when it comes time for pressure transient testing and analysis, Data Retrieval Corporation will be tops on their list.

Two-Rate Testing: An Alternative to Build-Ups and Drawdowns

noreply@spidr.com — Mon, 10 Nov 2008 16:21:57 EST

Pressure-transient testing is a valuable tool for a reservoir engineer. A properly executed test will enable the engineer to evaluate one or more of the following well properties: Skin, Permeability, Reservoir Pressure, Boundaries and Reserves. Typically these properties are acquired by either conducting a build-up or a drawdown test. However, circumstances may prevent the well from being shut-in, negating the possibility of performing either test. In this situation, the solution is to perform a two-rate test. A two-rate test is advantageous whenever any of the following is a concern: Loss of Production (Cash Flow) Wellbore Liquid Accumulation Difficulty Returning a Well to Production By performing a two-rate test, the operator avoids the loss of cash flow associated with the shut-in time necessary for either a build-up or drawdown. A well that is shut in generates no income. Wellbore liquid accumulation is a concern for wells that would develop a standing liquid column upon shut-in. If this occurs, reservoir response is masked until the liquids re-inject. Depending upon the volume of liquid and the kh of the reservoir, this could take a significant amount of time, making the build-up test an unreasonable option. During a two-rate test where both rates are above the critical unloading velocity, this liquid column does not accumulate; the reservoir response is valid during the entire test. The potential difficulty of returning a well to production is the final concern. In some instances, after a well has been shut in for a test, it is difficult or impossible to return the well to pre-test flow rates. There is little point in running a test if it results in a permanent reduction of well productivity. Running a two-rate test eliminates this potential risk. Analysis of a two-rate test is relatively straightforward. Build-ups and drawdowns are essentially special cases of a two-rate test, with one of the rates equal to zero! The permeability equation is the same equation associated with conventional build-ups and drawdowns: In this formulation of the permeability equation, the flow rate is employed in the calculation is the first rate of the two-rate test. The skin equation is somewhat different due to the fact that it incorporates both rates: Finally, the initial reservoir pressure, Pi can be obtained by the following equation: With these equations, a properly executed two rate test can provide the same information that a build-up or drawdown can, without the loss of cash flow or other associated concerns. The graphs below are Cartesian and Semi-log Plots from a two-rate test in which the second rate is approximately 33% larger than the first. Figure 1 Cartesian Plot Figure 2 Semilog Plot with Radial Flow Identified

Testing After the Storm

noreply@spidr.com — Mon, 10 Nov 2008 15:39:10 EST

Pressure transient testing is one of the cornerstones of well diagnostics. Reservoir engineers utilize the data collected from their wells to make decisions that aid in extending the life of the field. The main obstacle to pressure transient testing is the reluctance to shutting in a producing well. However, in the Gulf of Mexico, shut-ins are frequently dictated by the arrival of hurricane season. These mandated shut-ins provide the opportunity to acquire valuable reservoir data. With the 2008 hurricane season past us, many wells are still shut-in due to platform and pipeline damage that occurred as a result of hurricanes. With these extended storm shut-ins, operators in the Gulf used these shut-ins to obtain reservoir parameters for their wells. One major GOM operator gathered static shut-in tubing pressures (SITP) by calling out SPIDR gauges prior to the re-opening of their wells. DRC converted the SITPs to bottomhole conditions and the results were used to satisfy the annual MMS (U.S. governmental entity) survey requirements. This quick and simple test saved the operator time, money and production. Other GOM operators utilized the extended shut-in and the SPIDR system to capture not only the SITP but also collect the subsequent drawdown or flowing test data. The operators called out the units while the wells were still shut-in and had the SPIDR gauges recording when the wells were placed back online. When they were ready to resume production, the well was opened at a constant choke. By doing so, they were able to analyze for permeability and skin. One operator took full advantage of the mandated shut-in and performed an extended drawdown test when production resumed. The extended drawdown consisted of 45 days of constant choke-size drawdown. The extended drawdown enabled the operator to capture pressure transient data that DRC used to calculate permeability, skin and P*, but they were also able to utilize this post-hurricane drawdown as a reservoir limits test to determine the boundaries of the reservoir. Acquisition of these critically important reservoir properties was made possible by an unscheduled and unwanted shut-in mandated by the hurricane. When the decision of shutting in production has been made for you, the many reasons for not testing have been remedied. The remaining major issue encountered with this type of testing is the uncertainty of when the wells will be placed back in production. To address this concern, DRC has developed a pipeline shut-in proposal. This proposal offers lee-way in the rental charges resulting from extended shut-in days due to pipeline start-up dates being delayed. Along with storm mandated shut-ins, there are planned shut-ins for pipeline or facility work where the operator will have advance notice of both the shut-in and the start-up. In either case, the use of the SPIDR system includes the benefits of having a DRC reservoir engineer aid in the specific test plan for your well. DRC engineers are always available for free well test consultation and well test planning. DRC routinely aids in optimizing well test procedures for their clients. The SPIDR is delivered overnight in the U.S. and typically within 3 days internationally.

Pressure Build-ups (PBU) vs. Static Gradient Survey / Flowing Gradient Survey

noreply@spidr.com — Mon, 10 Nov 2008 15:37:16 EST

During a recent international marketing trip we have found that many operators of high rate gas and gas condensate wells perform Static Gradient Surveys (SGS) and/or Flowing Gradient Surveys (FGS) as opposed to Pressure Build-up or drawdown tests. The reason frequently given is that operational procedures dictate that a well must be shut-in when running wireline into the wellbore. By shutting in the well, before running wireline into the wellbore, you have introduced a major pressure transient into the reservoir that distorts the results from a subsequent build-up test unless you are willing to extend the flowing and shut-in times drastically. This is something the operator is rarely willing to do and therefore he only performs a SGS and/or a FGS. When surveillance work is limited to Static and Flowing Gradient Surveys they are losing the opportunity to acquire critically important reservoir information such as completion efficiency (skin), permeability and reservoir pressure (P*). The need to derive skin and permeability thru transient testing is invaluable as you seek to understand not only the change in reservoir pressure over time due to depletion effects but also understand the changing nature of kh due to formation compaction, etc. and if skin is accreting over time due to precipitates or fines migration that tend to restrict flow in gravel pack completions. Utilizing surface pressure measurements for pressure transient analysis avoids the concerns associated with running tools into a flowing well. The SPIDR well testing system has been performing that function for almost 25 years in gas and high-yield gas condensate wells all over the world. The system consists of the data acquisition unit, the SPIDR, and a very sophisticated computer model that converts well head pressures to reservoir conditions. The computer model takes into account frictional losses in the flowing wellbore, thermal effects in the well bore during rate changes, and phase changes in the wellbore going from flowing to shut-in conditions. One of the primary ways that DRC demonstrates effectiveness compared to downhole gauges is to perform a simultaneous trial comparison. A downhole gauge is run to TD while the SPIDR is simultaneously capturing pressure data at the wellhead. To maximize effectiveness and value, a PBU, as a minimum should be performed. If the SPIDR converted data proves to be acceptable to the customer and SPIDR Surface Well Testing Technology is deemed as a NO RISK and LOW COST alternative to running downholethe SPIDR can be used for future pressure transient testing surveys WITHOUT operational concerns.