Transmissive Fracture Detection

This presentation is to be presented at the 2019 Permian Basin Water in Energy Conference. The conference will be from February 19th to the 22nd and this presentation will be seen at 8:30 a.m. on Friday February 22nd. More details will be available at that time.

 New Insights on Transmissive Fractures and Water Production from the Horizontal Well Revolution

A Presentation to the 2019 Permian Basin Water in Energy Conference

February 20-22, 2019 

Technology Day –Friday 2/22/19

Steve Melzer, Melzer Consulting

 New Insights on Transmissive Fractures and Water Production from the Horizontal Well Revolution 

L. Stephen Melzer, Melzer Consulting, Midland, Texas 

1) Perplexing Questions

2) The Two Classes of Unconventional Plays in the Permian Basin

3) A Quick Look at the Horizontal San Andres Play

4) Hor SA Play Analogs (optional)

5) A Transmissive Fracture Case History (San Andres)

6) Can Mass Spectrometry Mud Logging Add Valuabe Contributions to Reservoir Understanding and Completion Engineering

7) Crustal Connections and Sour Wells in the Shales

8) Where to go from here?


Have you ever asked yourself how one horizontal well in a shale can produce sweet oil and the adjacent lateral, landing at the same depth, can produce sour oil? Or, have you ever asked someone what is the best way to avoid drilling into a transmissive fracture or what is the best way to control low oil cut laterals? Or, perhaps, how do I minimize the risk that my disposal wells will see curtailed injection, or worse, be shut‐in? Technologies to gather the diagnostic measurements and the science needed to address the questions are just now appearing. Lessons being learned in the horizontal San Andres play are needed to be applied now to the shales and are the subject of this presentation. 

We start with the obvious. Topping the energy news, maybe around the world, is the advance of horizontal drilling and completion technologies opening up reservoirs for commercial production that were only wild dreams in years past. The unconventional reservoir world that has changed the face of U.S. oil and gas production is often labeled ‘shales’ but those are the deep basin deposits historically branded as source beds and formerly excluded from economic reservoir opportunities. With all the attention on the shales, a quiet, behind‐the‐scenes play has evolved in very recent years which could also be labeled unconventional but now in the sense that the oil is unconventional and the reservoir is conventional, exactly the opposite of the unconventional shales. The play most often exploits residual oil in the carbonate shelf environments and does so by depressuring the reservoir and allowing the entrained gas to expand and release the oil. Because the oil takes some time to get depressurized, the wells tend to produce large volumes of water for some period of time before the oil tends to flow within the reservoir. The IPs are not as great as the shale laterals but, since the reservoirs are conventional, the decline curves are often much flatter than the shale wells. 

The San Andres Formation in the Permian Basin is not unique but, at 4000‐5500’ depth, leads the way with this new type of horizontal play. There are over 500 laterals producing today making about 40,000 bopd. The laterals are all within the mapped area of the San Andres residual oil zone (ROZ) fairways where numerous non‐commercial wells and dry holes were drilled during the age of vertical drilling. These zones were laterally swept by mother nature but leaving about 30‐45% of the oil behind in the oil‐

wet San Andres formation. Where the lateral sweep was not extensive, the solution gas remains in the oil providing the necessary drive when depressuring. 

Many of the ROZs beneath the major San Andres oilfields have been studied since the 1990’s as companies tried to quantify the oil saturations and whether the oil could be successfully CO2 flooded like man’s waterflood have been since the 1960s. Examples of 300‐400’ thick ROZs have been studied in this fashion. Research on the ROZ led to successful modeling of the sweep regional process and mapping of the ROZ fairways. Those studies have now been complemented with reservoir data coming from the horizontal laterals and are leading to some exciting discoveries related to the active processes in the ROZ reservoirs what were inhibited and unnoticed in the San Andres main pay zones. Many of those identified processes are related to bio‐geochemistry and owe their effects to naturally occurring anaerobic microbes which are believed now to be responsible for the oil wetting of the dolomites, creating the ubiquitous presence of sour oil and gas, and retaining the high levels of residual oil saturations. 

With the observations regarding the degree of natural lateral sweep comes some fascinating new hypotheses. Gas‐oil ratios, viscosity, and solution gas composition all seem to correlate with the degree of lateral sweep. New industry advances such as mass spectrometry mud logging, measurements‐while‐drilling (MWD), through pipe logging, and Pason© data all can be used to assess the reservoir and oil properties throughout the lateral. Examples of transmissive vertical fractures have been found and some even displaying evidence of hydraulic connection to the crustal rocks. These transmissive fractures allow a dynamic flow path for water and oil and dissolved crustal chemicals and intensify the same processes identified in the ROZ intervals. Sulfur present in the anhydrite, Organo‐sulfides, and/or iron sulfide minerals in the reservoir rock provide the energy for the microbes to do their work which include releasing of H2S into the fluids. The occasional sour oil well in the shales is now believed to owe its presence to the microbial activity freed from its own inhibitory processes to work in the hydrodynamic environment. 

Of very high potential value would be a tool to find those transmissive fractures. A horizontal well case history in Andrews/Gaines county region of the Permian Basin San Andres carbonate shelf illustrates the convergence of several diagnostic measurements to illustrate the presence of a 6’ wide, rubble‐filled vertical fracture that resulted in very high water cuts, low produced water salinity and suppressed oil gravity. The observations made using insights gained in the carbonates are just now being projected to the shale reservoirs to explain anomalously high water cuts and the presence of sour oil. Is locating local, short‐circuiting pathways of injection water to the crustal rocks yet another of the applications of these new insights?