SPEDC September 2016 Executive Editor Summary

 

 

Dear readers,

As many of you might be aware, we had some recent changes in the way SPE organizes itself. And therefore I would like to use this space “to spread the word” by citing here parts of the incoming Completions Director’s note from Jennifer Miskimins (Colorado School of Mines) posted in May 2016 (accessed 8 August 2016, please feel encouraged to read all of it on www.spe.org/disciplines/completions/ !): “SPE’s Board of Directors has created a new ‘Completions’ technical discipline, concluding that the interests of SPE professional members from the drilling, completions, and production and operations communities would be best served if Completions became a separate technical discipline.” The new Completions discipline includes the following major technical categories:

  • Completion Selection and Design                                    
  • Completion Installation and Operations
  • Well Monitoring Systems/Intelligent Wells                 
  • Sand Control
  • Hydraulic Fracturing                                                              
  • Acidizing
  • Completion Fluids                                                                  
  • Completions Evaluation
  • Recompletions                                                                        
  • Well integrity
  • Fundamental Research in Well Completions              

Currently, there are no plans to change the format of our journal SPE DC, but in the longer term you could expect some more articles about stimulations, which will be a welcome addition. And because for our Drilling colleagues nothing changes, and for our Completions colleagues a wider coverage can be looked forward to, in my view, our readership will benefit from this reorganization.

And now on to our articles, meant as support for your professional endeavors—because an approach that has the potential to lower unit technical cost in your area of responsibility may be offered in only a few lines, or paragraphs, further below.

 

Completion

Our first completion article in this issue of SPE DC aims to address a frequently asked question when stimulating unconventional shale gas wells: How much fracturing fluid will be imbibed (lost), and how much could be expected as recoverable?

In paper Experimental and Numerical Study on Spontaneous Imbibition of Fracturing Fluids in the Horn River Shale Gas Formation, the authors discuss laboratory experiments conducted with different fracturing fluids (0.07% polyacrylamide friction reducer, 2% KCl, and 2% KCl substitute) on cores with varying clay contents from this Canadian shale gas province, and how these were used to adjust their numerical, spontaneous imbibition model, assuming capillary pressure as the driving force. Experimental limitations and suggestions for further investigations are also shared.

They conclude that clay content (mineralogical analyses) and contact angle are the most important factors, while total organic carbon or porosity showed less influence on the systems investigated. Recommendations are provided on which fracturing fluid to use, dependent on the shale formation’s clay content, to reduce fluid loss. And, perhaps, you might want to check if this could be applicable in your unconventional gas play, too.  

 

The next article is a “must read” for all colleagues concerned with deteriorating (i.e., from calcium sulfate precipitation) seawater-injector performance, especially in carbonate reservoirs.

In Stimulation of Seawater Injectors by GLDA (Glutamic-Di Acetic Acid), after a detailed literature review, laboratory experiments (thermal stability and solubility tests as well as carbonate coreflood experiments) with two chelating agents ethylene diamine tetra acetic acid and GLDA are presented, investigating their feasibility as an HCl substitute.

The authors show that dosing GLDA at surface into seawater has the potential to avoid “traditional” and costly coiled tubing well interventions for injectivity restoration (i.e., by HCl treatments), and should be feasible without corrosion inhibitors or any other additives. The required volume of GLDA is comparable to that of HCl, with the additional advantage of less health, safety, and environmental exposure and injection operations continuing without any interruption often associated with well-intervention activities. You could have a discussion with your trusted chemist if this might be something to investigate further for your seawater injection scheme.

 

With the following paper we offer a kind of “refresher” and some useful calculations for colleagues interested in hole cleaning of horizontal wells with stationary pipe [i.e., coiled tubing drilling, or (plug) milling], which was the reason to group it under Completion. But of course, Drilling colleagues can also benefit!

Following a literature review about cuttings transport in highly inclined wells, article Quantitative Evaluation of Critical Conditions Required for Effective Hole Cleaning in Coiled-Tubing Drilling of Horizontal Wells presents experimental results from flow loop tests [9 m (29.5 ft) long with non-rotating and non-buckled inner pipe] with sand sized cuttings (260–1,240 m) and different circulating fluids (water and solutions with varying polymer concentrations). First, a cuttings bed is deposited, and afterward, the pump rate/flow velocity is gradually increased while monitoring when the particles start to move. Study limitations (i.e., concentric inner pipe and particle Reynolds Number range) are openly discussed.

In the appendices, calculation steps to correlate the friction factor and to obtain the critical flow rate are provided for Newtonian and non-Newtonian fluids. The authors conclude “that water always initiated cuttings movement at lower flow rates and pressure loss than polymer solutions.” Or, in (my) simple terms: If you want to prevent cuttings bed deposition, viscosify the carrier fluid. But, if you need to erode an already deposited cuttings bed (sometimes difficult to prevent from building up), pump a Newtonian fluid (i.e., water) above critical rate.

 

If you are tasked with providing realistic well time (hence, cost) estimates for management and shareholders, our next article is for you, describing the approach taken by an operator in the British North Sea and how it evolved over time.

Paper Probabilistic Well-Time Estimation Revisited: Five Years On presents the analyses performed on a data set of more than 200 wells with the majority drilled in two adjacent UK Continental Shelf quadrants of the Central North Sea (since 2005). Factors influencing time estimates [i.e., mechanical non-productive time (NPT), waiting on weather (for semisubmersible, jackup, and platform rigs), rate of penetration variation with depth, high-temperature/high-pressure well specifics, bit life metrics, well complexity factor, and learning curve/rig slow-down] are discussed together with the selected statistical analysis method.

The authors strongly recommend that all historical “trainwrecks” (long-duration mechanical NPT events greater than 2.5 days) need to be looked at together (lumped) to obtain a statistical and meaningful population size allowing predictions, and in doing so, they were able to achieve a remarkable 2 to 3% accuracy of well-time estimates for a year’s drilling activities (15 to 20 wells). An approach to potentially remember the next time you are called to justify an “adjusted” drilling authorization for expenditure in front of the board?

 

Our next drilling paper describes how the process of root-cause-failure analysis (RCFA), usually performed on equipment failures, was applied to investigate unsuccessful primary liner cementing operations on a tension leg platform well in the Gulf of Mexico.

In the article Root-Cause-Failure Analysis as a Tool for Investigating Operational Failures: A Case Study, the authors start by describing the operations before cementing the 7 5/8-in. production liner, which led to sudden and severe mud losses, making it necessary to set the liner top packer and pump the cement job with a closed annulus. Because zonal isolation requirements could not be met by this cementation, remedial work was needed resulting in 7 days of NPT. Subsequently, the RCFA process execution (i.e., gather and analyze data) is presented together with a discussion of the potential root cause for the sudden mud losses experienced.

As a result, the operator made a discussion of flow rate ramp-up procedure and target flow rate mandatory during the respective prejob meetings to increase awareness of all personnel involved. In addition, the RCFA team also developed a real-time monitoring tool, which enhances the interpretation of already available data when monitoring for critical indicators (e.g., torque spikes and pump pressure or flow rate changes) during such pumping operations. The authors are to be commended for sharing this mishap (often we get to read success stories only) and—at least my—main learning from this helpful case history is that the RCFA process can be applied successfully also in case operations (vs. equipment) and are to be investigated.

 

Achieving a tight seal is the objective of most pumped cement jobs, but fractures within the cement sheath or debonded microannuli provide potential leak paths with the risk of enabling undesired fluid migration. One method to tackle this problem is to investigate how these pathways could be sealed off again once present.

In The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells, the authors describe a pH-sensitive polyacrylic acid polymer (pH ~2.5) swelling into a gel after neutralization (i.e., when exposed to a highly alkaline environment such as Portlandite) in hydrated cement (pH ~13). They further present the laboratory experiments conducted on split cement cores with different fracture surfaces, which revealed that the injected polymer dispersion is influenced by two effects: The viscosity increase from elevated pH-value (desired) and solid polymer deposition after reaction with calcium leached from the cement (undesired because of jeopardizing the gel blockage). Therefore, fracture pretreatments with chelating agents for calcium control were investigated, too.

The authors conclude that in cement fractures pretreated with sodium triphosphate (Na5P3O10), the created gel structure can withstand the tested fluids to an average equivalent pressure gradient of 58 psi/ft (1320 kPa/m), which should be sufficient for most applications. Admittedly, I (layman) had to look up a few terms in the literature, but for all others, this paper is certainly recommended as “thought provoking.”

 

What do you do if you have to provide expert support to drilling operations all over the globe, but there is no budget—or you simply do not want or need—to build and maintain a permanently staffed (24/7) real-time drilling operations center? Well, in that instance, please read on.

In the article Real-Time Operations Support for Geographically Dispersed Operations, the authors share in detail how a mid-sized operator defined the requirements (central vs. local decisions and organizational setup), implemented the associated communications and data infrastructure (sourced out), introduced the pivotal role of a “real-time operations focal point” within the drilling community, established communication protocols, and subsequently tested the concept before “going live.”

The authors show that the idea of a “virtual” real-time operations center, only congregating if and when needed, worked well during the initial test, and also share their experiences during the first 6 months after its implementation. Perhaps an approach that could provide additional expert support for your rigs, too?

 

That’s it for our third issue in 2016. On behalf of the entire Editorial Review Committee, I thank you for your continued support of SPE Drilling & Completion.

 

Kind regards,

 

Christoph Zerbst

christoph.cz.zerbst@pdo.co.om

 

 

Christoph Zerbst is a senior production technologist at Petroleum Development Oman, Muscat, Oman and the Shell Principal Technical Expert (PTE) for Conceptual Completion Design. Most recently, he worked as lead production technologist for Sakhalin Energy in Yuzhno-Sakhalinsk, Russia, and as senior production technologist at Brunei Shell Petroleum in Seria, Brunei Darussalam. Before joining Shell in 2002, Zerbst spent 12 years with Wintershall in various production and completion related capacities. He has worked in several geographic locations mainly in production operations, completions (design and installation), workovers and well interventions (planning and execution) and field development, permanently based and on rotation, for on- and offshore fields. Zerbst has volunteered as Technical, Associate, and Executive Editor for SPEDC since 2003 and became SPE Peer-Apart honoree in 2010. He also serves as member of Task Group API Specification 19AC, Completion Accessories. Zerbst holds a Dipl.-Ing. (M.E.) degree in Petroleum Engineering from Technical University Clausthal in Germany.