Have you read this whitepaper?

SPE paper 169539:

Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses

by R.D. Barree, J.L. Miskimins, and J.V. Gilbert, Barree & Associates.

Over the last twenty years, Diagnostic Fracture Injection Tests, or DFIT’s, have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic fracture treatment parameters. Thousands are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results due to either problematic data acquisition or incorrect analysis of the acquired data.

This paper discusses common issues and mistakes made while acquiring DFIT data, and provides details of what the author believes to be guidelines and rules of thumb on how to avoid them. It goes on to addresses potential problems that can occur during DFIT analysis, and more specific issues such as poor ISIP data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, and the use of gelled fluids.

Although industry thought-processes may have changed slightly since the paper was published in 2014, the ideas presented by the author are as relevant as ever   — remember, you only have one shot at performing a DFIT correctly!

The paper can be downloaded HERE from OnePetro.

Real-Time Data Integration – A Case Study

Several months ago, Reservoir Data Systems was called upon by a notable client to provide real-time solutions on a large-scale data project. The client allocated an annual budget of $500k for the project, with the hopes of capturing DFITs on 50 wells ($10k being the average expected cost per gauge rental per test). Using memory gauges, the average test time was 20 days.

RDS Real-time Case Study Highlights

By utilizing Reservoir Data System’s EBOT Surface Pressure Gauges, FLOWBOT Flowing Rate Meters, and proprietary FASTRACK Real-time Communications Package, the client was able to view the data in real-time, which would result in significant gains of cost and efficiency.

By means of the RDS user portal, the client was able to visualize the tests in real-time  — they were able to actually see the pressure data, rather than hoping the memory gauge had captured everything reliably. Receiving the data instantly also allowed the customer to perform rolling analyses on each test, effectively cutting the total time of each test in half.

RDS Real-time Case Study Savings Figures

The significant time savings allowed the client to capture an additional 60+ wells of data while staying within the original budget. The incremental cost to perform the same amount of tests using the memory gauges, at twice the test length, would have increased their budget by over 600K.

The Reservoir Data Systems FASTRACK Real-Time Communications Package gives users a quick, easy, and cost-effective way to integrate real-time data into their operational processes — we help our clients make better, smarter, and faster decisions, while saving them both time and money.

RDS Real-time Benefits

For more information, CLICK HERE!

2017 Year in Review & Looking Ahead

Season’s Greetings from RDS!

It’s been a productive 2017 for us as the industry has started to respond to improved market conditions, and we are proud to say that we did not sit idle during the recovery period. We instead used the past year to strategically improve upon our services, grow our team, and continue to advance our company.

As another year of growth and reflection comes to a close, we would like to take a second and share a brief overview of the industry trends we observed over the past 12 months.

2017 saw a sizeable upsurge in onshore activity from clients who are major players in oil and gas — and it’s no surprise that a substantial amount of this activity was in the Permian Basin. We observed an increased demand for our REAL TIME data transmission services coupled with EBOT (surface) and JBOT (downhole) pressure gauges, as operators have once again begun placing emphasis on better understanding reservoir characteristics. We are seeing more DFITs and Frac Interference Monitoring with the operator’s intent of applying captured depletion, net pressures, BHP, etc. to their “big data” systems to make more informed decisions going forward.

It is also worth mentioning that we noticed different strategies employed by our small to mid-sized E&P clients. Many of these, particularly the smaller, private equity-backed, have begun using RDS to perform DFITs to better understand recently acquired fields, or to expand upon portfolio details in preparation of marketing their acreage position. Additionally, in this class of operator we saw a rise in both interest and utilization of newer technologies relating to Frac Interference Monitoring and emphasis placed on well-spacing optimization.

Looking at trends for 2018, we anticipate activity levels to improve further still as confidence in the market is restored and companies are eager to advance the development of existing acreage and prove up new acquisitions.

On the RDS front, next year will see the release of innovative new service lines and tools, and a full reimagining of our online portal that will change the way you receive data!

Best wishes to all for 2018, and stay tuned for more updates after the New Year. Have a safe and happy Holiday Season!

— The RDS Team

Hurricane Harvey Relief

Though much of Texas’ coast is still reeling from the initial blow of Hurricane Harvey, it has been subsequent flooding that has brought massive and wide-reaching devastation to the Greater Houston Area and beyond. The painful sting of loss and ruin knows no race, gender, creed, or social status – it is a universal hurt that is shared by everyone.


Headquartered in the Houston area, Reservoir Data Systems is no stranger to the wicked weather patterns of the Gulf Coast, and though we’re not invulnerable to acts of God, we count our blessings to be amongst the lucky few to have escaped Harvey’s wrath. That being said, our heads hang low and we weep for our brothers and sisters that did not fare as well — our hearts lay broken amongst the wreckage of so many family homes, businesses, schools, and places of worship.


Regardless of circumstance, it is in times like these that the human spirit is insurmountable. Families, neighborhoods, and communities will all band together, hand-in-hand, with love, compassion, and selflessness, to rebuild.


In the challenging months ahead, the RDS family will stand steadfast with Houston on it’s turbulent road to recovery. Working in tandem with Second Baptist Church, we hope to provide whatever assistance needed to as many of those that need it.


If Hurricane Harvey has impacted you or someone you know, or if you would like to join us in volunteering, please reach out to us and let us know.  Share or visit this link to Second Baptist’s homepage for relief support, volunteer opportunities, and donations.



URTEC 2017

URTEC 2017 is NEXT WEEK– Come by booth 803 and say hello!

SPE DFIT Conference Takeaways



Two weeks ago, Reservoir Data Systems sponsored a DFIT Processes and Applications SPE Workshop in Houston and it was a huge success!  Over 90 industry experts, experienced engineers, and distinguished academics came together to share best practices and provide valuable insights. 

Before the workshop, I spoke to various reservoir and completion engineers from different companies about their DFIT programs.  Several folks asked the me the same question—how do we creatively use DFITs to maximize value to the organization?   In other words, what all can we do with a DFIT program?  How do we maximize the ROI for DFITs?  What other advantages can we realize?

I was so pleased and intrigued when operators shared their DFIT stories at the workshop.  One of the most significant take-aways (there were several) from the workshop was hearing the ways operators found value (oftentimes unintentionally) from their DFIT programs.  I want to share a few of these with you.  Below is a brief summary from the workshop on ways operators have used DFIT information to bring value in development decisions:

  • The Life of Pi: Describe and understand initial pressure for more accurate reserves calculations. DFITs remain the best way to quantify initial pressure in unconventional and pseudo-unconventional reservoirs
  • To stagger or not to stagger: Optimize well spacing and placement.  DFITs in parent and child wells can provide a measure of depletion and therefore help operators determine the most cost-effective well spacing patterns
  • Put your field on the map: Recognize attributes and patterns that hinder fracture growth and map it out accordingly. Use this to visually determine the optimal completion and well placement strategies
  • Go off the deep end: Outline your vertical profile so you can find pressure anomalies and potentially uncover stacked-play possibilities
  • Turn on the lights: One DFIT test in a field is like lighting a match in a dark room, but a DFIT program will turn on the lights. Performing DFITS provides crucial pieces of information that, when combined, can really show the big picture and aid in decision-making

Obviously, there are other ways to utilize a DFIT program to add value and insight for development decisions.  We will be writing on the above topics in more detail over the next few months.  In the meantime, please comment on other ways your team or organization has advantageously used DFIT information, realized value from DFIT campaigns, or measured the ROI from a successful DFIT program?  Looking forward to the hearing from you!

URTEC 2016 – Making Data Great Again



Our experience at URTEC 2016 was one for the books! Amazing exhibits, papers, and technical talks topped off by networking with industry thought leaders from around the globe—what a conference!

It was an honor meeting so many amazing, forward-thinking folks with a passion for innovation in the O&G world– their optimism and dedication to advancement, despite uncertainties both forward and behind, is truly contagious!

Top Engineering Processes Based on Value

Game strategy drawn on blackboard

Process  /ˈpräˌses,ˈprōˌses/ noun – a series of actions or steps taken in order to achieve a particular end.

Without a doubt, a Petroleum Engineer’s playbook is massive. Processes, operations, procedures, or whatever you want to call them, are collected by the hundreds from the first day a rookie engineer steps foot into the office. With so much information ingested at a constant rate, it is easy to see how the fundamentals, however relevant they may be at the time, can become forgotten.

However, the dip and subsequent slow-rise in the price of oil has had many veteran engineers turning way back in their playbooks to find those tried and true processes with a single goal in mind: Value. The operations below are a handful of “plays” from RDS’ own engineers that they feel offer exactly that, in both cost-effectiveness and pertinent well data.


Diagnostic Fracture Injection Test (DFIT)

What it is:

In it’s simplest form, a DFIT is a low-volume frac procedure (sans proppant) carried out until initial fracturing occurs. From there, pumping is ceased and the well is closed off with the intent of capturing the subsequent natural pressure decline. Since DFITs are typically carried out immediately prior to hydraulic fracturing, the only additional equipment needed to conduct the test are surface pressure gauges and flow rate meters.

What it tells you:

DFITs aide in the planning of e­fficient well stimulation in low-perm reservoirs that demand extensive stimulation to achieve economic production. By mimicking actual fracture conditions, several design parameters can be extrapolated from the test, such as: Reservoir Pressure, Instant Shut in Pressure (ISIP), fracture gradient, net fracture pressure, fluid efficiency, and fluid-loss coefficients.


Minimal equipment, Invaluable data, High Value/Cost ratio


Depending on geological conditions, DFITs may take anywhere from 2-14 days.


Offset Frac Monitoring

What it is:

Offset Frac Monitoring is exactly that: monitoring the surface pressures of wells adjacent to a frac well. Whether those adjacent wells are on the same pad, or merely in the vicinity, it is good practice (and federally mandated for some) to identify any inter-well communication.

What it tells you:

Data revealing inter-well pressure interference or communication in certain zones can lead to corrective measures to prevent operational disasters and optimize well spacing, subsequently maximizing safety and production (respectively).


Low Cost, Invaluable Data, Minimal Equipment (depending on scope of job)


??? (***Editor’s Note: In all honesty, the only “downside” to this test is that it costs money at all. This is a test you should be running any time you are fracturing in proximity to adjacent wells.***)


Acoustic Well Survey

What it is:

From the surface, an Acoustic Well Sounder uses sound waves created by the tool and recorded by an internal microphone to survey a designated portion of a well. When the surveys are completed, the reflections of the sound waves (or kicks) are compared to well schematics and analyzed for anomalies.

What it tells you:

Acoustic Well Surveys can yield a wide array of subsurface information: fluid level and bottom-hole pressure determination, obstruction/parted pipe location, gas lift testing, work over/completions monitoring, and barrier verification.


Noninvasive, High Value/Cost Ratio, Invaluable Data


Results of this test can be easily skewed/rendered unusable – conditions for surveys must be ideal and personnel performing the operation must be skilled.


Build Up Test

What it is:

Usually reserved as a secondary process to be carried out during a planned shut-in, the basic procedure of a Build Up Test goes like this: install a pressure gauge to wellhead, record 15 minutes of flowing pressure data, shut the well in, and record the gradual increasing pressure until it levels off.

What it tells you:

The brilliance of this test is its simplicity and value vs. cost benefit. Although it does not garner the same attention as other tests that yield extensive well information, Build Up Tests help determine two key reservoir properties: reservoir permeability and skin damage.


Low cost, Minimal Equipment, Invaluable data


This test can only be carried out while well is shut in.

Decrease Costs: Offset Frac Monitoring


Let’s get right down to it:  As a Petroleum Engineer working in 2016, one of your daily priorities is to determine that every procedure carried out is money well-spent. Bad economics are a reality in the industry and such an emphasis on cutting cost has impacted many business units –some teams are at a complete standstill, while the most fortunate have completely shifted their goals to accomplishing more with less. But in the wake of collapsing budgets, one thing is holding fast: Well data is essential.

There is a long list of reasons engineers collect well data…and an even longer list of tools used to do it, but there is one operation that can actually lead to saving you money (in addition to the valuable data): Offset frac monitoring with surface pressure gauges. The ways offset frac monitoring can save you money are numerous, but I have highlighted a few below.


Well Spacing Optimization

Optimizing well spacing, particularly in ultra-low permeability formations, is one of, if not, the most important factors to consider regarding peak field production. The idea behind maximizing yields from a reservoir involves careful planning of well location and the orientation of each subsequent frac, to ensure the wells in a network are working together, not competing, to achieve optimal drainage. Sounds elementary, but it’s a delicate procedure – space wells too close together and you could be left with one or more wells competing for the same yield, space wells too far apart and you risk leaving money in the ground.

Monitoring the pressures of offset wells during frac procedures is one economic way to ensure your wells are properly spaced. For the marginal cost of a few surface pressure gauges, offset frac monitoring can help in a big way – insuring maximum production for new wells and forecasting any effect on existing wells, or locating geological anomalies such as naturally-occurring fault locations.


Frac Design Optimization

Generally speaking, the basic idea of hydraulic fracturing isn’t too complex…it is the design and application of that basic idea that can get convoluted. After an ideal candidate is selected, and formation data is measured or estimated, hours of work must be put in to determine specific details such as pad volumes, injection rates, fluid properties, proppant types, proppant volumes, and pump pressures/equipment. Without careful consideration and monitoring, these aspects could easily turn a profitable well into a glorified money pit.

Luckily, offset frac monitoring can help determine some of the data for you, ensuring your frac procedures run as lean and economic as possible. Specifics such as pad volumes – which can dictate the overall volume of which to pump, diversion strategies – which can direct or redirect frac propagation to a certain orientation, proppant volumes, and required horsepower to pump can all be carefully monitored via offset wells at the surface to make sure you’re not overspending on superfluous treatment.


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