Engineer's Corner : DRC - Data Retrieval Corporation

Remote Interference Monitoring of Offset Producers during Stimulation Operations

noreply@spidr.com — Fri, 18 Nov 2011 11:57:12 EST

The drilling of horizontal wells is increasing rapidly throughout the oil and gas industry due to enhanced reservoir contact and thereby enhanced well productivity, especially in unconventional, ultra low permeability areas. It has become evident these low perm reservoirs will require multiple horizontal wellbores to be drilled on much tighter spacing than in traditional plays. In the last several years hydraulic fracturing has advanced, and using horizontal, multi-stage fracturing has become a common process. This has caused concerns with many operators as an adjacent producer to a well stimulation may be knocked offline or otherwise be affected by varying degrees of frac interference. Operators ultimately want to understand the severity of this communication / interference with nearby wellbores and how it correlates with well placement and frac design. An interference/communication test can be used during the stimulation job to determine its affect on nearby offset producer(s). This is done by monitoring the wellhead pressures (shut-in or flowing), of the offset producer, during each frac stage. These studies allow operators to better understand the magnitude of interference in a given plane 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. It can also be valuable information to have especially when fracing close to lease lines as interference problems could result in legal claims upon an operator. Recently many customers have inquired about the SPIDR's ability for remote communication. Operators want the capability to simultaneously watch pressures from offset wells during hydraulic fracturing. This would allow them to make rapid on-site decisions if needed, whether that be for production optimization purposes or for early warning of a need for remedial action. DRC has recently developed a way to supply remote communication for operators. We can now provide a radio communication system in conjunction with the SPIDR that simultaneously monitors up to two offset wells. This radio communication system facilitates the delivery of pressure responses from the monitored wells to the frac van for real time observation. The remote radio communication system requires the following: SPIDR gauge(s) Base station radio with antenna Radio with antenna for each offset well Laptop computer for USB connection to base station The SPIDR gauges are rigged up to the offset well following the normal installation procedure. The SPIDR gauge is then connected to the radio through the SPIDR communication port. The base radio station is setup inside the frac van on location and is connected to a laptop supplied by DRC via a USB cable. The base radio station communicates through radio transmissions to each offset well. A DRC representative is sent to the location to ensure proper installation and confirm the system is working properly after which the system operates unattended by DRC personnel. Figure 1 displays the schematic for the remote radio communication system. The maximum reliable "line of sight" distance tested from base station to each offset well is one mile. If there is not a clear line of sight between radios, communication may be disrupted, although the use of extended antennas will aid in these situations. The communication system is battery operated and can operate up to 60 days. DRC recently conducted a field trial for an operator in the Eagle Ford shale. The operator requested to have real time pressure readings from two producing wells during the frac job using our radio communication system. The SPIDR was connected to both wells during the stimulation of the nearby well. One of the offset wells was 1000 feet away while the other was 3000 feet from the active well. The readings from the two offset wells were sent to the base station where the pressure could be monitored from inside their frac van. The SPIDRs were preprogrammed to send a reading every 3 seconds, however the SPIDR is able to record a data sample per second if necessary. There was a strong signal from one of the offset wells, but a weak signal from the well that was further away. This was due to the positioning of the antenna on the frac location, which was causing the signal to be blocked by the frac tanks. DRC has fixed this issue for future jobs and will now provide a portable mast that allows us to extend the antennas on the observation wells and the frac van. Overall, the customer was pleased and the remote communication system was considered a success. Horizontal, mulit-stage fracturing is now a common practice and as a result of this, we will continue to detect interference/communication on nearby wells. Therefore understanding the severity of the communication will be essential. If well placement isn't carefully considered during well planning, production could be affected. The SPIDR system with remote radio communication allows operators to monitor adjacent producers and send real time pressure readings to the frac van during stimulation operations to monitor interference. This system offers a low cost, no risk approach to providing operators with the ability to closely observe specific pressure responses during each frac stage. The SPIDR gauge allows detection of the smallest pressure change possible without wireline trucks or well intervention. Please contact DRC for rental availability of the remote communication radio system.

Wellbore Storage

noreply@spidr.com — Thu, 4 Aug 2011 16:16:47 EDT

Wellbore Storage is not a factor on deep, dry gas, low perm well when testing from the surface! Wellbore storage can be a concern in wells with two characteristics: wells with a near wellbore limit, or wells with long storage times. For wells that have a near wellbore limit, wellbore storage may mask the pressure transient encountering this limit. This could lead to misinterpretation of the pressure transient test and erroneous characterization of the well. For wells with long storage times (greater than 24 hours for example), the length of the shut-in required to derive useful data from a build-up test may not be economically feasible. In situations like these, use of a downhole shut-in tool to reduce the duration of wellbore storage should be considered. A wellbore storage question that we frequently receive concerns performing pressure transient tests from the surface on low perm wells. As outlined in a previous DRC Newsletter article, The Effect of Wellbore Storage on Surface Data , there are 3 primary factors that contribute to wellbore storage: Permeability of the producing formation, Compressibility of wellbore fluids and Volume . There is nothing we can do to increase permeability or decrease the compressibility of produced fluids which leaves us with only VOLUME to manipulate. By running a downhole shut-in tool or when testing below a closed ball valve on a DST string you are dramatically decreasing wellbore volume and thus dramatically reducing the potential effects of wellbore storage on low permeability formations. It should be noted that downhole pressure gauges deployed on wireline (without a shut-in tool) and pressure taken from surface measurements would be equally affected by wellbore storage effects as the VOLUMES are the same. From our experience, many operating company engineers are overly concerned about potential wellbore storage issues where testing results indicate it shouldnt be a concern. The following test example (click link for wellbore storage example) serves to demonstrate that wellbore storage effects are of no consequence in this specific well that is produced from a formation well below 20,000 ft. deep. The well has 3 production tubing installed and a calculated (see analysis, page 2) permeability of <1 md (0.7) with dry gas production. This well has all three characteristics (low permeability, large volume and highly compressible fluid) that would make many engineers believe that testing with a shut-in tool would be mandatory. The test results suggest otherwise. In this case the derivative (see plot, page 6) allows you to observe the end of wellbore storage approximately 6 minutes into the shut-in (10-1 hrs.)! Thus, we can conclude that Wellbore Storage is not a factor for surface transient testing of wells with similar characteristics. This article also serves to give you an example of our analysis report and what is delivered to you in our standard report. We convert the SPIDR recorded WHP (with customer supplied information on the specifics of the gas composition, fluids and wellbore diagram) to BHP and then analyze the converted data set to determine skin, permeability and P* as a NO RISK / LOW COST alternative to deploying wire and pressure gauges downhole. We utilize semilog or MDH analysis as our primary analysis method, but develop a derivative plot to check or verify radial flow.

SPIDR used in Steam Injection Applications

noreply@spidr.com — Thu, 4 Aug 2011 16:08:54 EDT

Steam Injection is a tertiary recovery method and the application is typically reserved for shallower, heavy oils as a method to reduce viscosity which allows the oil to more readily flow to the wellbore for production. DRC is increasingly seeing interest in operators for utilizing SPIDR surface measurements for capturing various parameters (injection pressure, steam injection rate, temperature) for steam injection applications around the world. The SPIDR can be used for injection / fall-off or two rate testing in steam injectors. The SPIDR System continues to be positioned as a NO RISK / LOW COST alternative to running wire and pressure gauges downhole. Injection temperatures for the applications we have been involved with have been in the 480 to 500 F range where running any type of electronic pressure gauges downhole for any length of time would be inadvisable. For the most accurate WHP to BHP conversion possible we look for applications where supercritical (single phase) steam is being injected into the well and reservoir. Because the SPIDR uses a unique 20 ft. x 1/16 Stainless Steel capillary tubing for the transmission of pressure (see diagram below) from the wellhead to the SPIDR, the gauge is not subjected to the high steam injection temperatures that would otherwise render it useless. See diagram below. Because the SPIDR can record up to three (3) processes the common Steam injection configuration is to record injection pressures via our internal dual quartz transducer, capture steam injection rate / cumulative injected volumes via our d/p cell across an orifice plate at the nearby meter run and injection temperatures at the wellhead via our temperature probe and thermowell installation on the wellhead or injection line. The two external transducers are connected back to the SPIDR via electrical cables of a length usually not greater than 50 ft.

Injection Fall-off (DFIT): Accurate Pressure AND Rate Measurement

noreply@spidr.com — Thu, 4 Aug 2011 13:04:02 EDT

DRCs SPIDR system has been recognized over the years for its ability to record accurate, temperature compensated wellhead pressure for traditional Pressure Transient Analysis. Our unique ability has been accurately converting WHP to BHP under a wide variety of wellbore conditions using algorithms that we have developed over the past 26 years. However with the market shift towards unconventional reservoirs, a significant percentage of our tests now being performed are pre-frac injection fall-off tests aka DFITs (Diagnostic Fracture Injection Test). Analysis of the DFIT data is the most critical part of these tests and requires certain features in a surface gauge. When performing a DFIT, it is critical to utilize a surface gauge with the ability to record high frequency, high resolution data. Detection of subtle pressure changes over a short period of time is essential in analyzing the fall-off data accurately. The DFIT test not only requires accurate pressure data, but also a precisely recorded injection schedule. Recording quality rate data is a vital process for a DFIT in order to achieve the desired results of the test. It is not uncommon for operators to receive poor quality rate data or no rate data at all. To effectively analyze the data knowledge of the pumping rate, rate stability, fluid volume, and pump shut down is important. For instance, rate stability is critical in recognizing breakdown and pressure effects during injection, and accuracy of the instantaneous shut-in pressure (ISIP) is imperative because it affects the net pressure and delta pressure plots, which in return can affect the interpretation of the test. The SPIDR system is significant in DFIT testing due to its high frequency, high resolution data while having the capability to simultaneously record accurate injection rates. It can interface directly with any size turbine flowmeter when using a magnetic pickup supplied by DRC. The SPIDR will record the pulses output by the turbine meter and convert the data to injection rate using the coefficient of the meter. It allows the user to pick volume units: barrels or gallons, as well as time units: minutes, hours or days. Figure 1 displays a chart of standard SPIDR compatible turbine sizes and their operating ranges. The calibration factor can be defaulted according to the meter size, or the actual meter factor can be inputted to provide a more exact flow rate and volume. Figure 1: Standard Turbine Flowmeter Sizes Our FLOWCOM software is used to plot the injection rates, cumulative injected volume, and pressure as a function of time, which are all key components for the DFIT analysis. Figure 2 displays a recent DFIT. The blue line represents the wellhead pressure, the red line is the instantaneous rate, and the green line is the cumulative volume pumped. Combining precise injection rate data with the SPIDR pressure allows you to perform accurate injection fall-off tests. Figure 2: Recorded Pressure and Injection Rate Click image for larger view. Operators have routinely used our SPIDR system for pre-frac injection fall-off tests because of its capability to record both high resolution, high frequency data and accurate injection rates. The SPIDR with our turbine meter pickup is available for rental and can be delivered overnight to any U.S. location and within 5 days to most international locations.

DFIT Analysis When On Vacuum At The Surface

noreply@spidr.com — Thu, 4 Aug 2011 12:27:46 EDT

A DFIT is an optimal type of test to perform using surface acquired pressure data. This is because the fluid being injected into the formation is incompressible; the surface pressure data will mirror the downhole pressure data so long as the well doesnt go on vacuum at the surface. The fluid column will be continuous from the perfs up to the surface gauge, and the only difference between the downhole pressures and surface pressures will be that of the hydrostatic head of the fluid column. The data requirements are high resolution (0.01 psi) and high frequency (1 sample/sec), and it is important that the gauge is also not influenced by external temperature fluctuations that may distort the shape of the fall-off data. Our SPIDR gauge is the industry leader in regards to surface pressure testing, and weve seen a large increase in the number of DFITs being performed over the past year. For the majority of these, the well does not go on vacuum at the surface and the surface pressure data acquired is an exact representation of the downhole pressures. However, we have seen some tests where after a period of time the well does go on vacuum at the surface. After that point, the surface pressure is no longer representative of the downhole pressures, and analysis on the data after that point is not possible. This does not, however, mean that a well cannot be tested from the surface if it goes on vacuum. Depending on how quickly the well goes on vacuum, valuable formation characteristics may still be determined from the surface data. This article will present a recent test performed on a well that went on vacuum a few hours after shut-in. Both the SPIDR surface pressure data and downhole pressure data were recorded and analyzed and it will be seen that the analyses from the two tests yielded the same results. Figure 1 below shows the SPIDR surface data (pressure scale on left y-axis) and the downhole pressure data (pressure scale on the right y-axis) overlaid with each other so that the shapes of the curves may be compared. The y-axes cover the same span of 1,100 psi in 100 psi increments. It can be seen that at about 35 hours the shape of the surface pressure starts to differ from the shape of the downhole gauge data, and that after about 38 hours the well is on vacuum at the surface. It can be seen that prior to 35 hours, the surface data is a direct representation of the downhole gauge data. Thus the only question is did we capture enough useful information prior to the well going on vacuum to perform an analysis and get meaningful results? Figure 1: Linear Comparison of Surface and Downhole Pressure Data Click image for larger view. The following six plots show the pre-closure analysis performed on the surface and downhole pressure data. It is important to note that the downhole pressure data is gauge pressure and the surface data is absolute pressure, so 14.7 psi needs to be added to the downhole gauge results when comparing with the surface results. Also, only the surface data up to where the well goes on vacuum was used for analysis, however the full downhole gauge data file was used for the downhole data analysis. It can be seen in the plots below that the analyses are very similar; they yield the same closure time, closure pressure, net pressure, stress gradient, and efficiency. Click image to review each plot illustrating pre-closure analysis. This well took enough time to go on vacuum to get useful data for a pre-closure analysis, and permeability can also be estimated from this pre-closure data as well. The after closure surface data however was not suitable for analysis for P* and permeability due to the well being on vacuum. It is important to understand that the length of time it may take for a well to go on vacuum is dependent on reservoir pressure and permeability of the formation, and thus it may not be possible to use surface pressures for the DFIT on all wells. But it is an incorrect assumption to say any well that goes on vacuum at the surface cannot be tested from the surface. The vast majority of wells we have tested do not go on vacuum at all at the surface, and the after closure data provides valuable reservoir information for future modeling work. In the cases where the well does not go on vacuum, downhole gauge data has no advantage to surface data, and is in fact simply more costly and comes at a much higher risk. Our DFIT analysis is complementary when the SPIDR gauge is rented for the purpose of capturing DFIT data. DRC will work with you to help determine if your wells can be tested from the surface, and we are available to discuss any well test procedures or data to help answer any questions you may have. We are available anytime to help plan your upcoming tests or to look at any previous test data you may have to help determine a better path forward.

Data Requirements for DFIT Testing

noreply@spidr.com — Fri, 6 May 2011 15:42:24 EDT

The bulk of the data recorded by SPIDRs over the years has been for Pressure Transient Analysis (PTA); here at Data Retrieval Corp. we perform hundreds of PTA tests every year for our clients. We have made it our business to be PTA experts in this industry, and over the past 25 years we have learned a number of key factors related to obtaining useful data to be used in the PTA tests. A DFIT test is a relatively new type of PTA test being performed in the tight gas sand and shale plays so prevalent in the industry today, and as such is subject to the same data requirements as a more traditional test such as a pressure build-up (PBU) would be. The objective of this article is to highlight those data requirements as they pertain to DFIT testing and illustrate just how critical high quality data is for achieving the desired results of the test. Pressure Transient Analysis is the analysis of change, namely the change in pressure over time. Thus it is critical to measure the pressure accurately, with high resolution and high frequency, and for that measurement to be repeatable. In traditional PTA testing of high permeability wells, high frequency and high resolution were critical to obtaining data that could be used for the analysis. This is due to the fact that in a high permeability reservoir, change happens very quickly, and the amount of change is small. If the gauge being used is of poor quality, the test data will be useless for analysis. But DFIT testing is done on low permeability reservoirs. While the same gauge quality concerns dont hold true for a traditional PTA test on a low permeability reservoir, for a DFIT test they do. This is because the pressure changes we are looking for in a DFIT test can be subtle, and they happen in a small window of time. By using a low quality gauge you run the risk of missing closure or picking the wrong closure time, or possibly not being able to detect closure because the gauge could not detect the subtle pressure change. Additionally, the after closure data which is used in determining reservoir permeability and pore pressure happens late in the fall-off when pressures are declining at a very slow rate. A low resolution gauge, 1 psi or lower resolution, would not be able to provide data that could be analyzed for permeability and pore pressure as it simply would not be able to detect the subtle pressure differences over time at the end of the test. Another important aspect to consider concerning resolution and repeatability is noise in the data. Noise can also come in the form of poor temperature compensation of the gauge, as the case would be with day to night temperature swings or step functions that exist in the calibration of the gauge. Traditional PTA using type-curve matching uses computer software to generate a model of the reservoir based on user input, which then generates a derivative curve that is then fitted to the actual derivative curve generated from the test data. Noise in the test data is amplified when looked at in the first order derivative plot, so it is critical to have as little noise as possible in order to provide the best match. Several diagnostic derivative curves are used in DFIT testing in order to determine leak-off type, closure time/pressure, after-closure flow regime, etc. These are both first order and second order derivative curves, and second order derivative curves amplify noise even more than first order derivative curves. Even relatively low noise data can make the DFIT analysis extremely difficult if not impossible. Due to noise it may be impossible to determine if it is a closure event being seen in the data, or just noise. It may also be impossible to determine the slope of the after closure data to determine if pseudo-radial flow is being seen and if an after closure analysis should be performed. If an analysis were performed it would also be difficult to get the correct slope through the data to accurately determine permeability and pore pressure. A final requirement to consider is the thermal compensation of the gauge in regards to the shape of the fall-off, or the rate of the pressure decline over time. Because a DFIT is a pressure transient analysis, which is an analysis of the pressure change over time, it is critical that the data the gauge is providing is an accurate reflection of what is taking place in the reservoir, and is not a function of the temperature of the gauge. A gauge that has poor temperature compensation will provide pressure data that will change with gauge temperature and not what is happening in the reservoir. This is a separate issue from noise as the gauge may have a high resolution and the data may have very little noise, but over the duration of the test the rate of pressure decline is wrong due to the temperature influence in the gauge. The rate of pressure decline is critical for identifying leak-off type, the point at which the fracture closes, and the flow regime from the reservoir after closure has happened. If the gauge data is being affected by its ambient temperature, then any or all of these may be misidentified which would result in an incorrect analysis. The data may look fine, but it would not be an accurate representation of what is going on in the reservoir. Pressure Transient Analysis is the most powerful tool available to the petroleum engineer, but it is only useful when quality data is combined with proper analysis technique. A small savings in the expense of a test by using a low quality pressure gauge may result in a test that cannot be analyzed, and a complete waste of the total tests costs. It may additionally waste the only opportunity that was available to test these ultra-low permeability reservoirs. Data Retrieval Corp. provides the means to obtaining the highest quality pressure data available in the oilfield, and the technical expertise that 25 years of experience in Pressure Transient Analysis gives. We provide free consultation and well test planning, and are available 24 hours a day, 7 days a week.

The 4 Keys to Pressure Transient Testing from Surface (Part 4)

noreply@spidr.com — Fri, 6 May 2011 12:02:32 EDT

This is the 4th and final 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. Data Retrieval Corporation, which pioneered this technology with the SPIDR (Self Powered, Intelligent Data Retriever) in the 1980s, remains the dominant service company actively promoting and performing this work today. WHP to BHP conversion technology is often given little consideration because many Petroleum Engineering textbooks declare that it is only possible under dry gas scenarios (defined as <10 BBLS/MMSCFD liquid). Further complicating this testing technique is a lack of high quality surface pressure measurement devices. This lack of gauge quality introduces an error source into the WHP to BHP conversion process, further eroding confidence in this technology. We also see other reasons for skepticism in this technology 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. 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 and phase change behavior, 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 accurately mirror data obtained with downhole gauges located close to mid-perforations, there is NO VALID reason to not use surface measurements. SPIDR Surface Well Testing got its start in a geo-thermal, geo-pressured environment where wells are frequently deviated and often sour. The LOST TOOL STRING RISK along with the TOPSIDE (PERSONNEL/EQUIPMENT) RISK associated with running gauges downhole under these conditions were big drivers towards the use of surface testing technology, not to mention the enormous cost savings that benefit the operator. 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 the distinct advantages of testing from the surface. 4th Key Well Testing Procedures optimized for Surface Transient Testing The 4th key to optimizing results in surface transient testing is to minimize or eliminate thermal transients. Thermal transients (see figure 1) refer to the time it takes wellbore temperatures to stabilize and remain within a narrow range after a rate change. Figure 1: Thermal Transients DRC routinely encounters the effects of thermal decay on those wells that carry significant heat to the wellhead. Having the ability to adjust for temperature changes after rate changes is extremely important for the viability of our business model. The example plot in figure 2 serves to demonstrate that without a thermal decay component to correct for these effects, the surface data set is worthless for use in pressure transient analysis. Figure 2: Effect of Thermal Decay Our thermal decay models assume that thermal stability has been reached before the choke has changed or the well is shut-in for the pressure build-up. When changes are made to the flowstream before thermal equilibrium is reached it can cause errors because incorrect values are used in the calculations used for computing the thermal decay correction. Incorrect accounting of thermal decay results in an incorrect slope computation or what we often refer to as a relative error, the change in pressure with time (dp/dt) does not mirror that measured by a downhole pressure gauge. Minimizing thermal transients is normally accomplished via flowing at the same choke setting/or maintaining the well shut-in for longer periods than you would otherwise do if you were not testing from the surface. These problems typically manifest themselves in exploration well testing for example, or where on-site personnel do not properly follow the written testing procedures and they minimize the flowing and/or shut-in periods. Therefore, communicating with both engineers in the office and on-site engineering field operations to design test parameters with the mindset to optimize the process for surface measurements, is an important consideration to avoid or at least minimize these potential negative effects.

Candidate Selection for Surface Testing

noreply@spidr.com — Thu, 5 May 2011 15:01:58 EDT

Over the past 26 years, DRC has developed the SPIDR well testing system into the preeminent method of testing gas and gas condensate wells from the surface. Through this experience weve found one of the critical steps in the process of designing a surface test is selection of candidate wells. Conducting a surface well test on a well that is a poor candidate can result in erroneous reservoir characterization. With this in mind, determining that the well is in critical flow has proven to be the most important aspect of screening wells for surface testing. This article will discuss wells that are poor candidates because they are not in critical flow and also the pressure responses that may be observed in these types of wells. Wells that flow below the critical rate are poor candidates for surface testing. In order to accurately model surface pressures to bottomhole pressures, one of the constraints is that the well must have constant mass flow and constant component flow while on production. Wells that do not continuously unload their produced liquids satisfy neither of these criteria. The consequence of this is that flowing BHPs calculated from surface data will be in error because they do not account for the hydrostatic head of the liquid accumulating in the wellbore while the well is on production. This will also have an effect on the analysis for skin. Since the calculated flowing BHPs are too low, the Delta

DFIT Testing: Downhole vs Surface Data

noreply@spidr.com — Mon, 24 Jan 2011 10:39:07 EST

Data Retrieval Corp. has built its reputation over the past 25 years as the best surface well testing company by providing a blind comparison to downhole gauge data on a pressure transient test to new customers or in new areas. This has allowed for two things, first for the customer to see that DRCs technology works and is a viable substitute to running gauges downhole, and secondly to provide DRC with additional data with which to further improve our conversion models. Obviously those two work hand in hand to ultimately provide an ever better result for the customer, which is what our reputation is founded on. A significant percentage of our recent work has been minifracs or DFITs on very tight gas sands or shales. These tests involve pumping a relatively small volume (20-50 bbls) of fluid (typically 4% KCl or similar) into the formation over a period of 10-20 minutes creating a small fracture, and then shutting the well in and watching the pressure decline. Various properties such as fracture closure time and closure pressure, fluid efficiency, reservoir pressure, and permeability can be then be determined and used for later work. Because the fluid being injected is an incompressible fluid and is continuous from the perforations to the wellhead, surface testing is a perfect way to capture the data for these types of tests in a majority of wells. The conversion to downhole pressures is straight forward as the density of the fluid is well known. However there have been some concerns voiced over whether the results of an analysis on actual downhole gauge data would be the same as those from surface data. As we have done with our traditional PTA testing, we recently ran a test where a downhole gauge was also in the wellbore during the mini-frac while the SPIDR gauge was on surface. The results of this comparison follow, and show that surface data provides the same results as downhole data. Figure 1 and 2 are regression analyses on the surface and downhole data to determine closure pressure and time, net pressure, and fluid efficiency, and use the Nolte G function time. The downhole pressures in the surface data plot are computed based on the depth and fluid gravity input into the software, and the surface pressures in the downhole data are likewise computed. As can be seen, the results compare very well with each other. It should also be noted that the downhole data was gauge pressure and the surface data was absolute, so there is a ~15 psi difference to be expected. Figure 1) Surface Data Regression Analysis using Nolte G time Figure 2) Downhole Data Regression Analysis using Nolte G time Figures 3 and 4 are regression analyses on the surface and downhole data to determine closure pressure and time, net pressure, and fluid efficiency, and use the square root of shut-in time. As before, the downhole pressures in the surface data plot are computed based on the depth and fluid gravity input into the software, and the surface pressures in the downhole data are likewise computed. Once again as can be seen, the results compare very well with each other. Figure 3) Surface Data Regression Analysis using square root of shut-in time Figure 4) Downhole Data Regression Analysis using square root of shut-in time As can be seen from the previous plots, the surface data gives the same result as the downhole gauge data as far as determining closure pressure, ISIP, net pressure, and fluid efficiency are concerned. However it can be observed in the plots that there is a key difference between the downhole and surface data later on into the fall-off. This is due to the reservoir being under-pressured and the well going on vacuum at surface. When this happens, the surface pressure is no longer a reflection of what is happening downhole, and analysis results will be different. If the reservoir is under-pressured and the fall-off is of a short enough duration so that the well has not gone on vacuum at the surface, the results between downhole data and surface data will be the same. However for long fall-offs where the well has gone on vacuum at the surface before a full analysis can be done then only downhole gauge data can provide true, accurate results. For normally pressured or over pressured reservoirs the surface data will give the same results as the downhole data at all times. This is important to understand and plan for prior to performing minifrac or DFIT work. It can mean the difference between saving money and risk and getting useful results and simply wasting money and time on poor results. The conclusions to be drawn from this comparison are that surface data is a much safer, less expensive way to obtain minifrac data on a majority of tight sand and shale wells. The results from the analyses match up very well, and the shape of the data during the fall-off prior to going on vacuum at the surface is the same for both datasets. Any future work could be planned based on the analyses of either of the two datasets. It is important to understand the limits of testing under-pressured reservoirs from the surface, and to plan ahead to avoid wasted time and money on tests the yield poor results. Data Retrieval Corp. offers free consultation and well test planning for all your pressure transient testing needs, including minifracs or DFITs. We offer a complimentary analysis when a SPIDR gauge is used to capture the surface DFIT data, and are available 24/7 to assist in all your well testing needs.

The 4 Keys to Pressure Transient Testing from Surface (Part 3)

noreply@spidr.com — Mon, 24 Jan 2011 09:36:13 EST

This is the 3nd 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. Data Retrieval Corporation, which pioneered this technology in the 1980s, remains the dominant service company actively promoting and performing this work today. WHP to BHP conversion technology is often given little consideration because many Petroleum Engineering textbooks declare that it is only possible under dry gas scenarios (defined as <10 BBLS/MMSCFD liquid). Further complicating this testing technique is a lack of high quality surface measurement devices. This lack of gauge quality introduces an additional error source into the WHP to BHP conversion process, further eroding confidence in this technology. We also see other reasons for skepticism in this technology 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. 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 and phase change behavior, 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 accurately mirror data obtained with downhole gauges located close to mid-perforations, there is NO VALID reason to not use surface measurements. SPIDR Surface Well Testing got its start in a geo-thermal, geo-pressured environment where wells are frequently deviated and often sour. The LOST TOOL STRING RISK along with the TOPSIDE (PERSONNEL/EQUIPMENT) RISK associated with running gauges downhole under these conditions are big drivers towards the use of surface testing technology, not to mention the enormous cost savings that benefit the operator. 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. 3rd Key Customer Provided Input Information Incorporate accurate INPUT information into conversion algorithm software. I refer to INPUT information as something the Customer provides, such as: Gas Flow Rate, Liquid Yields, new or recent PVT analysis if a condensate producer. Any software program that utilizes a set of inputs to output results is only as good as the quality of the input information provided. Our situation is no different. In fact, we have discovered over the years that inaccuracies in our customer provided input information is the single largest source of error (whether absolute or relative) in our conversion from WHP to BHP. We continue to be surprised by the fact that a basic parameter such as gas flow rate measurements can be erroneous up to and even greater than +/-10%! In some cases, flow rate measurements are not even being recorded at the wellhead! It seems odd to us that conversion errors of 1% or even 0.5 are closely scrutinized when the real culprit seems to be a lack of processes in place to measure and report basic well parameters on a consistent basis. When testing from the surface, the objective is to closely replicate the downhole gauge data. However, inaccuracies in input data my result in ABSOLUTE or RELATIVE errors in the converted data. ABSOLUTE error refers to a SHIFT in the data set up or down while RELATIVE error refers to a difference in slope. RELATIVE error almost always means that we have not accurately accounted for thermal decay. This could be because the proper input temperatures were unavailable or that operational procedures were not optimized for transient testing (flow periods too short which didnt allow temperatures to stabilize). ABSOLUTE error is typically a problem of over/underestimating friction (during flow periods due to inaccurate rate measurement) or inaccuracy in measurement of a produced component (gas &/or liquid). At this point it is important to state that DRC does not claim and will never claim to be a replacement for downhole pressure gauges on ALL gas and gas condensate wells, but if your wells: 1. Are above critical unloading velocity and 2. Do not slug at the surface, they are certainly candidates for testing at the surface with our technology. The Applied Petroleum Reservoir Engineering book, by Craft & Hawkins, on Page 60 in the Gas Condensate Reservoir section, reveals that a dry gas well is generally described as having less than 10 BBLS/MMCFD of condensate. It is also typically recognized that dry gas wells can be pressure transient tested at the wellhead. Generally speaking we expect error (from WHP to BHP conversion) to increase as liquid yields increase. However it is important to understand the phase envelope of the reservoir. Many gas condensate wells tested from the surface produce significant amounts of condensate at the separator but are single phase in the wellbore or above the dew point pressure. Therefore, it is important to be cognizant of the phase envelope in relation to the total liquids produced. It is also important to understand the re-distribution of the gas/liquid ratios during a build-up or drawdown when the pressures are changing rapidly. Our ability to model these changes is dependent on a good PVT analysis. Because we strive to minimize error via comparisons between DHG data and our WHP to BHP conversion, it is important to understand that we utilize only one model (a modified cullendar-smith) backbone with add-on sub-models as liquid volumes and frictional contributions increase. Using multiple stand alone multiphase conversion models provides neither consistency nor reliability in the on-going conversion of pressure data. They are more often than not used as a substitute for the lack of quality input data, which is essential to replicating downhole captured pressure data. I think the comment below by a software model maker drives this point home. The comment below was lifted from a google search concerning multiphase flow models; The range of applicability of multiphase flow models is dependent on several factors such as, tubing size or diameter, oil gravity, gas-liquid ratio, and, two-phase flow with or without water-cut. The effect of each of these factors on estimating the pressure profile in a well is discussed separately for all the multiphase models considered. A reasonably good performance of the multiphase flow models is considered to have a relative error (between the measured and predicted values of the pressure profile) less than or equal to 20% Therefore, in contrast to the above conversion model methodology, our objective is first identifying the well / reservoir types where our model is valid, and then once those types are identified work to minimize conversion errors to less than 1% of captured or derived values.

Mechanical Integrity Testing with the SPIDR

noreply@spidr.com — Mon, 24 Jan 2011 09:28:02 EST

Mechanical Integrity Tests (MIT) on producing wells and disposal wells are required by both state and federal regulatory authorities. Both authorities are seeking assurance that well bore fluids cannot migrate to strata from which the well is intended to be isolated. This is accomplished by subjecting the well bore, any annuli and isolation hardware such as packers to pressures at or above the maximum design pressure. While DRCs SPIDR system was initially developed for traditional pressure transient testing, we realized early on that operators had many other applications for recording high precision pressure data. That is why the SPIDR was designed with the ability to simultaneously record up to three separate pressure data points. In addition to the SPIDR's internal precision dual quartz pressure transducer, the SPIDR can also read two external pressure transducers that can be attached to any pressure source. In this manner, up to two of these external transducers can be connected to a single SPIDR, enabling you to record three data points simultaneously at a rate of 1 sample per second. The diagram below shows an example installation of a SPIDR with two external transducers. Using this type of arrangement operators can easily measure casing, tubing, and annulus pressures. By cycling the pressures in the tubing and the various casing annuli, the operator can determine whether communication exists between these elements and the surrounding formation. The SPIDR is portable, weather proof and self-powered and can be used to measure almost any pressure source including pressures over 20,000 psi. In addition to pressure we also have the ability to measure differential pressure, temperature, injection rate or any other process that generates counts, such as a turbine flow meter or a pump meter. The SPIDR can be used as a portable high precision data recorder to satisfy almost any need. If you are interested in a customized solution contact us and explain your needs. We can configure a SPIDR to meet almost any data acquisition requirement.

Water / Gas Injector Testing from Surface Measurements

noreply@spidr.com — Thu, 30 Sep 2010 09:17:37 EDT

Measuring surface injection pressures and rates are routine applications for DRC. Water injector wells can be for produced water disposal or water flooding for secondary recovery and pressure maintenance programs. Gas injectors wells can be utilized for acid gas injection (disposal), for pressure maintenance, and for tertiary recovery efforts (i.e. CO2, N2, O2 & Steam). Testing applications usually fall into several categories: 1. Step-rate testing to determine fracture gradients 2. Injection fall-off to determine completion and reservoir properties. 3. Monitoring injection pressures vs. injection rate 4. Interference / communication monitoring between injectors and producers 5. Modeling injection pressures on pilot projects or conversions of producers to injectors. Transient tests for skin effects can be of the injection fall-off variety where a steady injection rate has been maintained for some period of time and the well shut-in with the pressure allowed to fall-off. Alternatively, a two-rate flow test may be performed (with significant differences in the injection rates) in order to determine skin and permeability. Using surface measurements is a fairly straightforward application as you have a column of liquid of a known density and length from which to calculate the hydrostatic head in the wellbore. The only critically important point to remember for using surface measurements on water injection testing is that the well must maintain positive pressure at the surface during a fall-off test. In other words, the well must not go on a vacuum. If the well goes on vacuum we would recommend performing a 2-rate injection test. High resolution and high sampling frequency surface pressure gauges can be used to capture pressure and injection rates for a variety of applications. The use of surface gauges for pressure transient tests on secondary and tertiary recovery wells is an effective NO RISK, LOW COST substitute for running wire and pressure gauges downhole. For steam injection testing there are limited and expensive downhole options for gathering pressure and rate information because of the elevated temperatures involved. DRC maintains a fleet of SPIDR gauges available for immediate delivery to your location via overnight FedEx or same day Hotshot service.

The 4 Key Elements in Pressure Transient Testing using Surface Measurements Part 2

noreply@spidr.com — Thu, 30 Sep 2010 09:11:29 EDT

This is the 2nd 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. Data Retrieval Corporation, which pioneered this technology in the 1980s, remains the dominant service company actively promoting and performing this work today. WHP to BHP conversion technology is often given little consideration because many Petroleum Engineering textbooks declare that it is only possible under dry gas scenarios (defined as <10 BBLS/MMSCFD liquid). Further complicating this testing technique is a lack of high quality surface measurement devices, This lack of gauge quality introduces an additional error source into the WHP to BHP conversion process, further eroding confidence in this technology. We also see other reasons for skepticism in this technology 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. 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 and phase change behavior, 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 mirror data obtained with downhole gauges located close to mid-perforations, there is NO VALID reason to not use surface measurements. SPIDR Surface Well Testing got its start in a geo-thermal, geo-pressured environment where wells are frequently deviated and often sour. The LOST TOOL STRING RISK along with the TOPSIDE (PERSONNEL/EQUIPMENT) RISK associated with running gauges downhole under these conditions are big drivers towards the use of surface testing technology, not to mention the enormous cost savings that benefit the operator. 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. 2nd Key Utilize a robust WHP to BHP conversion algorithm with a Thermal Decay component DRC started performing pressure transient tests from the surface in primarily dry gas wells in the 1980s utilizing a rudimentary Cullender-Smith routine for single phase dry gas applications. As we performed this work our customers increasingly asked us to refine our conversion algorithms to be able to test wells that produced liquids. The development of the DRC conversion algorithm has come in steps over the last 25 years and we have made significant improvements in the conversion process as we moved into high rate, high yield, large bore gas condensate producers around the world. A key element of our marketing program assists us in gathering the empirical information necessary to understand where our conversion process falls out of bed so that we can make improvements in the WHP to BHP algorithm. This marketing program provides for a FREE TRIAL COMPARISON between our surface acquired SPIDR data converted to BHP (WHP to BHP) and a downhole wireline conveyed gauge or a permanently installed pressure gauge. To qualify for this FREE TRIAL COMPARISON the operator agrees to provide DRC the downhole pressure gauge data file within 30 days AFTER we have provided him with our conversion and analysis. Not only are we demonstrating the capability of our technology to our customer under his well and field conditions but we are acquiring a copy of the downhole pressure gauge file run concurrently with the SPIDR which will allow us to review and potentially improve upon our conversion process under that operators field and specific well conditions. We have performed hundreds of direct comparisons over the years in a wide variety of wellbore conditions. It is a dynamic process that allows us to continue improving our conversion methods over time and with increased experience under a given set of field and well conditions. DRC promotes SPIDR technology primarily for gas and gas condensate wells that produce naturally (critical flow) and have constant component flow (no slugging at the wellhead). These are the two basic criteria we look for before recommending SPIDR technology as being applicable for a specific well. DRC surface testing technology is also used on oil wells with minimal water production and flows naturally in excess of 1000 BPD and above the "bubble point". The DRC WHP to BHP algorithm uses a modified Cullender-Smith backbone and employs individula modules to consider liquid production, flow velocities, friction loss, thermal decay and kinetic energy losses. Our experience in understanding when to employ a specific module for a given set of wellbore conditions continues to set our technology apart from any other oilfield service or commercial software provider with a WHP to BHP routine. In addition to utilizing SPIDR gauge data for WHP to BHP conversions we are increasingly asked to provide conversions for historical WHPs captured via existing SCADA, wellsite telemetry or other surface pressure data acquisition systems. We typically perform a QA/QC on the customer supplied surface data to see if it can be used for pressure transient testing purposes. Because the data quality (sampling frequency and/or resolution) is frequently inadequate, we may be unable to analyze the data or only provide a qualitative analysis to the customer. See Key # 1 of this series. Other applications that operators have utilized our conversion algorithm for are: a. Conversion of pressure data from gauge depth to mid-perf TVD . A permanently installed pressure gauge is located a large distance away from the reservoir because of completion limitations or excessive downhole temperatures. b. Conversion of Subsea Tree gauge data to mid-perf. TVD. When the permanently installed pressure gauge fails. This has proven an application for both oil and gas/gas condensate producers. Having a robust conversion algorithm is certainly one of the keys in allowing this technology to be successful, however on the next series we will discuss what impact the various INPUTS have in the accuracy / reliability of our conversion of WHP to BHP.

Pre-frac Diagnostic Injection Test Analysis

noreply@spidr.com — Thu, 30 Sep 2010 08:55:47 EDT

Over the past two years at Data Retrieval Corp. we have seen a marked increase in the number of Diagnostic Fracture Injection Tests (DFIT) performed along with an increased desire by our customers to get this test data analyzed and interpreted for use in planning future stimulation work and for determining reservoir characteristics. This has lead to increased discussions about the analysis methods and interpretation of these of tests. This article is intended to provide an overview of the information these tests provide, present the basic analysis plots and methods used to interpret the data presented on those plots, and provide an understanding of how the various diagnostic techniques work together in analyzing the DFIT data. DFIT tests provide information for future fracture design and also reservoir properties which are used for predicting future production. It is therefore critical that the test data not be misinterpreted. This article will deal with what is referred to as Normal Leakoff Behavior. Normal leakoff occurs with fracture closure which happens as a result of matrix leakoff after shut-in. After shut-in or cessation of the pump-in, it is assumed the fracture stops growing. Three analysis techniques will be looked at in this article: Nolte G-function, G-function log-log, and square-root of shut-in time. Examples for each technique will be shown, and the various curves used to help determine closure, leakoff mechanisms, and flow regimes will be outlined. First we will look at Nolte G-function method, which is the most commonly used pressure decline analysis technique. It accounts for mass conservation and fracture compliance and inherently assumes that the rate of pressure decline is proportional to the leakoff rate. Figure 1) Nolte G-function analysis technique, Normal leakoff behavior Figure 1 shows an example of the Nolte G-function analysis method using Meyer & Associates MinFrac software on a data set exhibiting normal leakoff behavior. Three diagnostic derivative curves are used in this technique to determine when closure occurs, the first derivative dy/dx, the semi-log derivative G dP/dG, and the G-function semi-log derivative subtracted from ISIP. The most useful of these three is the G-function semi-log derivative, shown as the gray curve in Figure 1. The expected response is a straight-line through the origin, and closure is indicated by the departure of this derivative from the straight-line 3A-3B which also passes through the origin. The other two curves also aid in identifying closure, as the minimum in those two should occur at fracture closure. Non-ideal leakoff behavior shows as slight variances in the semi-log derivative from the straight-line before the departure marking fracture closure. Additionally, the pressure vs. G-function should form a straight line during fracture closure, and departure from this straight line is also indicative of fracture closure. Next, we will look at the square-root of shut-in time plot and its diagnostic derivative curves. It is very similar in appearance to the Nolte G-function technique, and a single closure point (good agreement) must be found for both the G-function and square-root shut-in time plots. Figure 2) Square-root shut-in time analysis technique, Normal leakoff behavior Figure 2 shows an example of the square-root of shut-in time (Delta Time) analysis method using Meyer & Associates MinFrac software on a dataset exhibiting normal leakoff behavior. Once again, three diagnostic derivatice curves are used to help determine when fracture closure occurs, the first derivative dy/dx, the semi-log derivative x dP/dx, and the semi-log derivative subtracted from ISIP. Also, as in the previous example, the semi-log derivative curve (x dP/dx) is going to be the most useful curve for determining leakoff mechanisms and closure time/pressure. This curve is going to be equivalent to the semi-log derivative of the G-function in low permeability cases, which is generally the type of wells to which these tests are being applied. Just as before, closure occurs at the departure of the semi-log derivative from the straight line 3A-3B. The other derivatives once again should be at a minimum at closure, allowing for further confirmation of the closure pick. Like the G-function analysis the pressure vs Sqrt. Shut-in Time should form a straight line during fracture closure; however unlike the G-function analysis fracture closure is not marked by the departure from that straight line trend. This would lead to a later closure time and lower closure pressure. Rather the inflection point on the pressure vs Sqrt. Shut-in Time marks closure, and is most easily determined using the various derivative curves, particularly the first derivative where the inflection point is determined from it by finding its maximum. Finally, we will look at the G-function log-log analysis method. This method allows for a third confirmation of a consistent closure point, however the greatest advantage to this method is that it allows for flow regime identification during leakoff and after closure. This means we can determine if pseudo-linear, pseudo-radial, or full radial flow was seen after closure, and allow us to properly analyze the after closure data for reservoir characteristics. Figure 3) G-function log-log analysis technique, Normal leakoff behavior Figure 3 shows an example of the G-function log-log analysis method using Meyer & Associates MinFrac software on a dataset exhibiting normal leakoff behavior. Here we have only plotted pressure vs G-funtion and the semi-log derivative of the G-function, G dP/dG. The flow regime before closure, the closure point, and flow regime(s) after closure can be determined from these two curves alone, which will then allow for after closure analysis to determine reservoir characteristics such as transmissibility (kh/). It can be seen that the two curves are nearly parallel, which is usually the case immediately before closure, and the point at which these two curves then separate marks closure. This point should be consistent (in good agreement) with the G-function and Square root of Shut-in Time methods. The slope of these lines before closure is indicative of the flow regime during leakoff, for example a slope of is indicative of linear flow from the fracture. After closure, the slope of the semi-log derivative curve is indicative of the reservoir flow regime. A slope of - would indicate fully developed pseudo-linear flow, a slope of -1 would indicate fully developed pseudo-radial flow, and a slope of -2 would indicate fully developed radial flow. We will also take a quick look at after-closure analysis. Figure 4 and 5 below are examples of after-closure analysis on data that exhibited a pseudo-radial flow regime. Figure 4 is plotted on a cartesian scale and figure 5 is on a logarithmic scale. Figure 4) After-Closure Analysis, Normal Leakoff behavior, pseudo-radial flow Figure 5) After-Closure Analysis log-log, Normal Leakoff behavior, pseudo-radial flow In figure 4, the line 1A-1B is drawn to best fit the slope of the data, the slope of which then determines P*, the pore gradient, and kh. The derivative curve should begin to converge with the data in pseudo-radial flow, and should converge when in fully developed radial flow. In figure 5, the slope of line 1A-1B is set depending on which flow regime is identified. Here, since pseudo-radial flow was identified, a slope of 1 was used. This line then passes through the data, and it should be seen that the derivative curve is nearly horizontal during this time. The analyses for both these methods should be consistent (in good agreement) with each other. Even though they dont provide the high degree of accuracy that traditional transient testing provides for determining reservoir characteristics, Diagnostic Fracture Injection Tests are quickly gaining popularity in todays tight gas market where traditional pressure transient analysis is simply not practical due to the extended test times required. It is important to understand what can be learned from these tests, how these tests are analyzed and interpreted for future fracturing work and for prediction of post-frac. production performance, and the limitations of these tests and the analysis. Surface data is perfect for tests of this type, as it is much safer and cheaper to obtain and provides the same results as downhole data in almost all cases. DRC has been capturing data for clients on hundreds of these types of tests per year and we continue to see that number increase. We offer a basic complimentary analysis and interpretation on these tests when the data is captured via the SPIDR well test system, and continue to offer free consultation on well test planning.

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.