Engineer's Corner : DRC - Data Retrieval Corporation

Communication Monitoring During Frac Operations Downhole vs Surface

noreply@spidr.com — Thu, 7 Jun 2012 16:38:17 EDT

With the large number of wells being fractured in the tight sand and shale formations, it has become an increasing concern to operators when adjacent producing wells are knocked offline by a nearby frac. 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. Monitoring this data for several wells in real-time via radio communication, which DRC now offers, can also allow for on-the-fly adjustments to current fracturing operations. We have heard and even read recently that this type of work can only be done when data is captured downhole. This is not accurate. This type of test is easily conducted from the surface and in fact gives the exact same information as downhole gauge data would. We recently had the opportunity to perform this exact type of test for an operator who was fracing two wells that had three producing wells nearby. The operator used SPIDR surface gauges to monitor the three producing wells and also ran a downhole gauge in one of those wells. The monitoring wells were shut-in during fracing operations. The frac job was then carried out on the two new wells over the next several days. The accompanying plots show the surface treating pressure from the frac jobs along with the SPIDR surface data and downhole gauge data. Figure 1 shows the overall plot with all the frac stages for both wells, the SPIDR data from the three monitoring wells (red, blue, and green), and the downhole gauge data from one of the monitoring wells (black). The blue SPIDR data and black downhole gauge data are from the same well. It can be seen that there was communication in two of the monitoring wells (blue and red) but that the green well didnt seen any communication. The downhole gauge also showed the same communication that was seen in the surface data. Figure 1: Overall Plot Figure 2 and 3 are expanded views of the communication events from the first wells frac operations and then the second wells frac operations. These views clearly show communication from various frac stages, and that the same response (black and blue curves) was seen both downhole and at the surface. Figures 2 &3: Expanded Views of Communication from Frac Stages This test clearly shows that surface data is a perfect alternative to running downhole gauges for frac communication testing, and does so without most of the cost and any of the risk of running wire into the wellbore. DRC now offers a radio communication option that can be used to remotely communicate with several SPIDRs within ~1 mile radius, which allows for real-time monitoring of communication during fracing operations. This is not possible, or would be very cost prohibitive to do, with downhole gauges. DRC always has gauges ready for same day shipment via priority overnight delivery to most places in the United States, or same day via hotshot. We offer free well test planning and consultation, as well as complimentary DFIT analysis when a gauge is rented for the purpose of a DFIT, and are available 24/7 for all your well testing needs.

Properly Conducting a DFIT

noreply@spidr.com — Thu, 7 Jun 2012 15:36:37 EDT

For the past several years, the majority of tests performed by DRC are pre-frac injection fall-off tests aka DFITs (Diagnostic Fracture Injection Test). Analysis of the DFIT data is highly sensitive to the pressure data acquired, necessitating both high quality pressure/rate measurement and proper test design and execution. When performing a DFIT, it is essential to utilize a surface gauge with the ability to record high frequency, high resolution, temperature compensated data. Detection of subtle pressure changes over a short period of time is essential in analyzing the fall-off data accurately. In addition to quality pressure measurement, a DFIT also requires a precisely recorded injection data. Simultaneous acquisition of rate and pressure data provides the engineer a better understanding of operational activities during the test and will improve the results of the subsequent analysis of the DFIT. Without this data, 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. Furthermore, it is necessary for the DFIT to be conducted properly in order to get an accurate analysis from the fall-off data. The injection period is the most critical part of this test. Service companies must exercise caution when pumping low rate, low volume jobs as small errors while pumping can result in significant error/uncertainty in the analysis. There are key events which must be observed during a properly conducted pump-in. Initially while injecting pressures should steadily increase as the injection fluid is compressed in the wellbore. Next, there should be an indication of formation breakdown in order to establish communication with the reservoir. Pressures should also decrease as the fluid column relaxes during breakdown. After breakdown is observed, fluid is pumped until the planned volume is achieved or pressure has stabilized. While injecting, it is important to maintain a steady, constant rate to help determine breakdown and for verification of pressure stabilization. DRC routinely encounters pump-ins in the past where the rate was not stabilized and volume was not accounted for, making the test difficult to analyze accurately. Below are several examples of pump-ins which were performed poorly and examples of pump-ins we believe were performed correctly. Some of the poorly conducted pump-ins made the fall-off difficult to analyze while others made the analysis impractical. Figure 1 is an example of a pump-in where rate was lost immediately following the injection period. It was hard to determine when the pumps were shut down and what exactly happened during the test. In this instance it may have been helpful to have the rate data to aid in determining what may have occurred. Figure 1: Pressure was lost immediately after pump-in Figure 2 displays a DFIT where both pressure and rate were recorded. In this case rate was not held constant during the injection period. Figure 2: Rate was briefly lost during the pump-in Figure 3 shows an attempted step rate test. While performing a step rate injection it is important that each constant-rate step should take just enough time to allow the pressure to stabilize. Figure 3: Step rate injection performed poorly Figure 4 and 5 display DFITs where pressure and rate were recorded. Rate was held fairly constant and pressure was stabilized prior to shutting down. This resulted in an accurate analysis on both wells. Figure 4: A properly conducted pump-in Figure 5: A properly conducted pump-in Operators have routinely use DRCs SPIDR system in DFIT testing due to its ability to capture high frequency, high resolution pressure 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. Having the rate data will help understand whether or not the DFIT was performed correctly. Field personnel also have the option to watch the rate and pressure real-time via a supplied USB communication cable to help determine if the test is being conducted correctly or to make necessary decisions and changes. The SPIDR with 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. DRC is available 24/7 for your well testing needs. We offer free test planning and consultation and a complimentary DFIT analysis when a SPIDR gauge is used to capture the surface pressure data.

Understanding Wellbore Cooling

noreply@spidr.com — Fri, 1 Jun 2012 10:07:47 EDT

DRC has been conducting pressure transient tests from the surface for 27 years. Over this time we have developed many techniques to overcome the challenges that are uniquely related to surface testing. One of the most significant challenges to surface test is the matter of wellbore cooling. This article will discuss the nature of wellbore cooling as well as the work DRC had done to correct for it. Before discussing the effect that wellbore cooling has on surface testing it is useful to understand the basis behind calculating bottomhole pressures from surface data. The basic equation governing the conversion of wellhead pressure (WHP) to bottomhole pressure (BHP) is the following (ignoring kinetic energy and other negligible effects): BHP=WHP+ρgh+f. (1) In the above equation ρ gh is the hydrostatic head component of the wellbore fluid and f is the pressure drop due to friction. Since pressure transient analysis is the science of pressure change, looking at the change of each of these components results in this modification of the governing equation: ∆BHP= ∆WHP+ ∆(ρgh)+ ∆f. (2) Wellbore cooling begins once a producing well is shut in. While a well is flowing, the produced fluids are bringing heat from the reservoir to the surface raising the wellhead temperature (WHT). The amount of increase is due to a number of factors such as gas rate, liquid gas ratio, bottomhole temperature and the specific heat of the wellbore fluids. In some environments, this can cause WHTs to approach 300F! Upon shut-in, this heat source is lost, and the wellbore will begin to cool. As the wellbore cools, the wellbore fluid density and corresponding hydrostatic head both increase. Rearranging the above equation allows us to understand the effect this change in density has on surface pressures: ∆WHP= ∆BHP-∆(ρgh)-∆f. (3) For a shut-in well frictional losses are zero and thus ∆ f is zero. For moderate to high permeability wells ∆ BHP will be fairly small, as the pressure in the reservoir tends to stabilize fairly quickly. For these types of wells, the change in hydrostatic head ( ∆ ρ gh) will be larger than ∆ BHP, resulting in a negative ∆ WHP. This means the surface pressures will decline over the course of the build-up! This is one of the more interesting phenomena that one may encounter when conducting a build-up test at the wellhead. An engineer new to surface testing may mistakenly write this off as a bad test that cannot be analyzed. Experience has shown us that this is an effect of wellbore cooling during a build-up. At DRC, we have developed a proprietary thermal decay model that accounts for wellbore cooling. This empirical model was developed through testing with surface and downhole gauges simultaneously. It accounts for cooling wellbore temperatures over the course of a build-up and enables us to properly account for increasing hydrostatic head over the course of a shut-in. It is a vital component of our model and enables DRC to interpret datasets that would otherwise be unanalyzable or mis-analyzed. Figure 1 below illustrates the effect that correcting for wellbore cooling can have: Figure 1 Two pressure curves are displayed on this graph. The blue line represents the converted BHPs when we do not account for the increased hydrostatic head due to wellbore cooling. The red line represents the converted BHPs when DRCs thermal decay model is employed. For this test, correcting for wellbore cooling increased the final calculated BHP by over 100 psi. It is important to understand that regardless of the permeability of the well, wellbore cooling occurs during a build-up. Even if surface pressures continuously increase throughout the shut-in, failing to account for wellbore cooling will result in erroneous calculations for skin, permeability and P* Wellbore cooling is a complex phenomenon and a challenge that must be overcome when testing from the surface. To discuss this further or for any testing needs you may have, please call or email DRC at 281-444-5398 or drc@spidr.com.

DFIT Testing: Downhole vs Surface Data (Part 2)

noreply@spidr.com — Fri, 17 Feb 2012 14:06:56 EST

An article in DRCs Winter 2011 Newsletter discussed the use of SPIDR captured surface data as a perfect alternative to running downhole gauges for DFIT testing. This is due to the fact that the fluid being injected is an incompressible fluid and is continuous from the perforations to the wellhead. DFIT testing involves pumping a relatively small volume (10-50 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. The history of DRCs blind comparison testing against downhole gauges was discussed, and an example DFIT analysis was presented showing SPIDR captured surface data compared with downhole gauge data. This example showed that, up until the well went on vacuum at the surface, the results were an exceptional match. Unfortunately, due to the well being under-pressured, the well did go on vacuum at the surface and the later after closure data was not analyzable. This made a comparison of the later after closure fall-off data with the downhole gauge data impossible. In the time since that article was written, we have still heard from a few operators that running downhole gauges is preferable to them, for reasons varying from concern over the accuracy of the calculated downhole pressures obtained in the surface analysis, to concerns with temperature effects distorting the shape of the fall-off. We recently had the opportunity to run another DFIT comparison on an over-pressured reservoir where obviously the well does not go on vacuum at the surface. As a result, a comparison of the after closure data was possible. The results of the comparison are presented in this article and are a good update to our previous comparison article. Figures 1 and 2 below are the regression analyses for both the surface and downhole gauge data. Like in the previous articles example, the results for closure pressure and time, net pressure, stress gradient, and fluid efficiency compare very well with each other. Any subtle differences are simply the result of the limitations in the softwares resolution (how finely the slopes of the lines and placements of points can be determined) and my analysis techniques. Figure 1: Regression Nolte G Time Plot Comparison Figure 2: Regression Nolte G Time Log-Log Plot Comparison So the early time fall-off data shows excellent agreement between the SPIDR and downhole gauge, but what about the late time fall-off data? Figures 3 and 4 below show the after closure analysis results of the late time fall-off data. It can be seen that the results for permeability and P* are in excellent agreement with one another. Figure 3: After Closure Analysis Nolte FR Plot Comparison Figure 4: After Closure Analysis Nolte FR Log-Log Plot Comparison As these plots show, surface data gives nearly exactly the same analysis results when compared to the downhole gauge data. In fact, as explained before, the small differences in the analysis results are likely from limitations in the software and personal interpretation technique and not from the data itself. As long as the reservoir is normally pressured or over-pressured the surface data will mirror the downhole gauge data; the only difference being a scalar offset equivalent to the hydrostatic head of the liquid column in the wellbore. The added cost and risk from running gauges downhole is not justified for this type of testing. Additionally, the vast majority of these low permeability wells are horizontal and the downhole gauge is not ran to the toe stage where the tests usually take place. Thus there is a depth offset from the gauge to the perforations even with the downhole gauge. The same conclusions from the previous comparison article apply here, namely that surface data is a much safer, less expensive way to obtain mini-frac data on a majority of tight sand and shale wells. The results from the analysis match up very well, and the shape of the data during the fall-off 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 that yield poor results. As always, DRC is available 24/7 for your well testing needs. We offer free test planning and consultation, and a complimentary DFIT analysis when a SPIDR gauge is used to capture the surface pressure data.

SPIDR Data Storage Format and Output Options

noreply@spidr.com — Fri, 17 Feb 2012 12:48:26 EST

New users of the SPIDR system are frequently confused or unaware of the data format options that are available. This article explains how data is stored in the SPIDR and why it is stored in that fashion. It also describes the data output options available to the user. The original SPIDR was built in 1985. At that time the largest memory chips available were 2K (2,000 bytes). These chips had a large footprint and were very expensive. Only four of these chips could fit on the SPIDR motherboard thereby providing a total of 8K of memory. With only 8K of memory it wasn't possible to store enough data to meet the requirements of the typical pressure transient test. Because of this limitation, DRC developed an algorithm to allow for the acquired data to be stored in a highly compressed format that multiplied the effective memory capacity four times. However even this was not sufficient memory for most pressure transient tests so DRC developed the concept on "Intelligent Sampling" which led to the name SPIDR (Self Powered Intelligent Data Retriever). Intelligent sampling tracks the rate of pressure change (dp/dt) in the well and when pressure changes are small, the sample is discarded and when the pressure changes are large, the sample is stored. This concept allowed the effective memory to grow as much as 30 times! Intelligent sampling asks the user to set the sampling frequency and a pressure window. These values are then fixed for the duration of the test. Assuming the sample rate was set to 2 seconds and the pressure window was set to 3 psi, every 2 seconds the SPIDR would take a new pressure sample and compare it to the last stored pressure value in memory. If the difference was less than +/- 3 psi, the new sample would be discarded. If 29 consecutive samples were discarded the 30th sample would be stored regardless of change. In this manner a SPIDR could store as many 30 samples/minute or as few as 1 sample/minute depending on the rate of pressure change in the system being monitored. When used during a buildup or drawdown test, early in the test the pressures change very rapidly and every sample is stored. As the test proceeds, the rate of pressure change and the rate of data storage decline until the well reaches radial flow and the rate of data storage reaches a minimum. These concepts of data compression and intelligent sampling are very complex and required advanced programming skills in order to utilize the limited memory capacity of the available memory chips. Although at the time, we would have preferred not to have undertaken these steps, they have become essential for efficient functioning of the current generation SPIDR. With 5 Meg of memory as opposed to the 8K of memory in the original SPIDR it would have been unacceptably slow to download and process today's data files with more than a million samples. Another concept that is sometimes difficult to grasp is the variable size of a sample in SPIDR memory. In SPIDR terms, a "Sample" contains the following information: sample number, date, time, pressure, reading from channel 1 (if active) and the reading from channel 2 (if active). The memory required to store a single sample is therefore dependent on the number of channels active and the amount of pressure change between successive samples. Thus the SPIDR which has 5 megs of memory can store as many as 5 million samples or as few as 1 million samples depending on how many channels are active and how noisy the data is. It is for this reason that when "STATUS'ing" the SPIDR, it reports back not only the number of samples that have been stored but also the percent of memory still free. Communication with the SPIDR is accomplished with FLOWCOM, a free download on DRCs website . When the SPIDR is downloaded with FLOWCOM, two separate data files are created, one with the extension "DLD" and the other with the extension "MK2". These files are identical; however the DLD file is a "read only" file. It can be edited by the user in FLOWCOM but when the file is saved it is automatically saved with the MK2 extension and will overwrite the latest saved version of the MK2 file. If the edits to the MK2 files prove to be unacceptable for any reason, the DLD file is still intact with all of the original raw data and can be re-edited. The SPIDR can store up to 5 million samples however very few programs are available to allow the user to load or process a data file of that size. FLOWCOM offers many powerful editing tools to help reduce the data file to a manageable size. It is rare that all the collected data is useful. Frequently the SPIDR is recording atmospheric pressure before installation and that is that often the case after the test is over as well. The FLOWCOM editing tools allow the user to quickly filter out all atmospheric pressure and/or all data greater than a specified pressure or all data less than a specified pressure. If, after the extraneous data has been removed, the file is still too large to be read into Excel, FLOWCOM allows the user to condense the file to the desired number of readings by parsing on pressure change. The following is a screen shot of the editing options available in FLOWCOM. After the data file has been edited to the user's satisfaction, he can be export it in either of two ASCII formats, real time or delta time. A screen shot of the file export options screen is shown below along with examples of data in the two file output options. Each of these output formats can be directly imported into Excel. REAL TIME FILE Well Name: Example Sample Window :0.00 PSI Started on: 02/02/2012 at 10:31:04 Sample Rate: 00:00:01 Ended on: 02/02/2012 at 10:31:23 Max. Interval: 00:00:01 Number of Records: 20 Serial Number: N/A Filename: Example.TXT -------------------------------------------------------------------------------- Date Time Sample WHP (PSIA) -------------------------------------------------------------------------------- 02/02/2012 10:31:04 599465 1405.09 02/02/2012 10:31:05 599466 1440.08 02/02/2012 10:31:06 599467 1477.21 02/02/2012 10:31:07 599468 1516.55 02/02/2012 10:31:08 599469 1555.48 02/02/2012 10:31:09 599470 1593.81 02/02/2012 10:31:10 599471 1632.10 02/02/2012 10:31:11 599472 1669.35 02/02/2012 10:31:12 599473 1704.97 02/02/2012 10:31:13 599474 1742.48 DELTA TIME FILE Hours PSIA 0.000000 1405.09 0.000278 1440.08 0.000556 1477.21 0.000833 1516.55 0.001111 1555.48 0.001389 1593.81 0.001667 1632.10 0.001944 1669.35 0.002222 1704.97 0.002500 1742.48 Should there be any questions on the use of FLOWCOM or data file formats, remember that you can contact DRC 24/7.

Testing Oil Producers from Surface Measurements

noreply@spidr.com — Fri, 17 Feb 2012 10:58:40 EST

The most common misconception that exists about the SPIDR Well Testing System is that it is limited to only dry gas applications. Over the past 27 years, Data Retrieval Corporation has done extensive work to broaden the range of wells that can be tested from the surface. Currently, in order for a well to be a valid candidate for surface testing, it must adhere to the following criteria: Constant mass flow rate Constant component flow rate Effective fluid continuity from surface to bottomhole These conditions mean that the well must flow above the critical unloading rate and cannot have a gas liquid interface in the wellbore inhibiting communication between the reservoir and the wellhead. Based on these requirements, the following subsets of wells are considered good candidates for surface testing: Single Phase Wells a. Dry Gas Wells b. Gas-Condensate Wells that flow above the dew point c. Oil Wells that flow above the bubble point Multiphase Gas Wells that flow above the critical rate to lift liquids a. The well is below the dew point while flowing b. The well continuously unloads all produced liquids (i.e. no slug flow) c. The well can shut in above or below the dew point Some Multiphase Oil wells a. The well flows below the bubble point b. The well produces naturally c. The well exhibits a bubble-flow type flow pattern (SPE 77001) d. The well must shut in above the bubble point to test via build-up This is a significant expansion of the range of wells that can be tested from the surface beyond dry gas. To illustrate this expansion, an example of an oil well successfully tested from the surface is presented. The well shown below produces at a rate of ~1,500 BBL/d with a GOR of ~1,000 SCF/BBL. The FTPs for this well are below the bubble point for the produced fluid, but the SITPs exceed the bubble point pressure. A quick check of the superficial phase velocities confirmed that the well was also in bubble flow when producing. This well satisfies the criteria for a multiphase oil well that can be tested from the surface. A 72 hour build-up test was conducted on the well with both a SPIDR gauge installed on the wellhead and a DHG on slickline. The goal of the test was two-fold: The operator wanted to evaluate DRCs abilities to convert wells in this field as well as obtain an analysis for skin, permeability and P*. Once the test was completed, the SPIDR data was transmitted to DRC and then converted to the DHG depth for a blind comparison with the data. Once the conversion was submitted to the operator, the DHG data was transmitted to DRC so that both data sets could be overlayed. Figure 1 below is a linear comparison of both data sets: Figure 1: Linear Comparison As can be seen above, there is a small difference in the flowing bottomhole pressures, and very good agreement between the shut-in pressures. Figures 2 and 3 below are semilog and derivative plots of the data which were used to obtain analyses of the two data sets: Figure 2: Semilog Comparison Figure 3: Derivative Comparison These two plots show that, while there is a small difference in the early time data, for the most part the data sets virtually overlay one another. The early time difference is due to gauge placement; since the well is shut in at the surface, the SPIDR will see the shut-in response before the downhole gauge. The overall similarity of the curves should result in comparable results when analyzing for the wells reservoir properties. DRCs analysis of both data sets is presented in Table 1 below, confirming that the results are very close. Table 1: Analysis Comparison At DRC, we believe the goal of surface testing should be to provide equivalent results to those obtained from running downhole gauges. Based on this successful test, the operator will have confidence going forward that they can use the SPIDR well testing system as a no-risk, low-cost alternative for future well tests. Please contact DRC to see if your wells are viable candidates for surface testing. 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.

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.