Executive Summary

Please allow me to start with a very warm “Thank you!” to outgoing Associate Editor Simon James (Schlumberger). His widely recognized expertise, experience, and impressive erudition, together with dedication and a very supportive communication style to our authors, will be certainly missed. It was an honor working together for this journal. Luckily, even in these rather difficult times, we still have colleagues in our industry who are prepared to step up and volunteer. Therefore, it is my pleasure to welcome Lee Dillenbeck (Chevron), who has kindly agreed to support the Editorial Review Committee of SPEDC as an associate editor, with his expertise—especially, but not limited to—in Cementing.

Let me also use this space to encourage you as authors to not only contemplate submission of your (conference) papers to SPEDC, but to actually do it. Yes, it is additional work, and your paper, your brainchild, might be subjected to—constructive(!)—criticism, and ultimately may run the risk of being declined (not all of my journal submissions have made the cut), but I, personally,  find it very rewarding to see one's own ideas and approaches finally published after a thorough “sense-check” by industry experts. On a (much) wider scale, if we all assume that others will act, very little gets done; meaning knowledge dissemination within our industry will neither improve nor accelerate.  

After this appeal for less “moments of inertia," we move on to our articles, which hopefully offer some “food for thought” for your areas of responsibility.


Completion. Sometimes delays (i.e., several months) between well completion and actual production start-up are unavoidable. And if a sequence of viscous fluids has been introduced during well completion without subsequent cleanup (flowback) operations, one could [or should(?)] become concerned about the associated impairment risk during such waiting periods. An investigation of the consequences is offered in our first paper, presenting a useful case history from oil fields offshore West Africa.

In A Deepwater Openhole Gravel-Pack Completion With Prolonged Well Suspension Without Initial Cleanup: An Angola Block 15/06 Case History, after introducing the reservoir, the authors describe the selection processes for drill-in fluid, sandface completion [openhole gravel pack (OHGP) with shunt tubes], gravel-pack carrier and displacement fluids, the actual OHGP execution, and how the wells were suspended. After production had started, parameters such as skin factor or PI (productivity index) were compared with offset wells that had flowed-back much earlier (“within a few weeks”). It is shown that 14 wells, suspended for extended periods of 8 to 22 months could be “just” started-up “without any need for filter-cake cleanup,” with comparable (and low) mechanical skin factors and PI. Having occasionally heard “anecdotal evidence” that fluid damage over time was apparently not as bad as expected, I am grateful that the authors share some actual facts from their wells with us. 

Our next article is not only highly relevant for all colleagues working with coalbed/seam methane (CBM/CSM) wells, but also for everybody contemplating the substitution of slotted steel liners in shallow wells (say, <1200 m/3,900 ft TVD) by another material [i.e., polyvinyl chloride (PVC)].

In Integrity Testing of a Polyvinyl Chloride Slotted Liner for Horizontal Coalbed-Methane Wells, the authors first share their motivation to replace steel (cost, corrosion risk, safety—if the coal seam is subsequently mined), compare steel properties with plastic materials (polyethylene, polypropylene, PVC), present the load experiments performed (OD 110 mm/4.33 in.), discuss the results under aspects of PVC-liner deformation and failure characteristics, influence of slot geometry, and number of slots and describe the multi-objective optimization process developed by combining two models predicting a slotted liner’s skin factor and its collapse resistance. The authors conclude with recommendations for slot length, number of slots, slot density, and slot width, sharing the relative importance of each. The optimization approach is backed by actual experiments. In my view, sufficient details are shared to allow replication by interested colleagues to check if slotted-PVC liners could be an economic option in your specific situation, too. 

Drilling. For the safe and economic execution of drilling activities, a reliable pore-pressure prediction (PPP) is highly important. Therefore, our industry has established tools and workflows available to obtain the same. Supplementing those, our next paper offers an alternative approach to pore-pressure estimation that is based on drilling efficiency (DE) and the mechanical specific energy (MSE) needed in the process of “making hole."

Pore-Pressure Estimation by Use of Mechanical Specific Energy and Drilling Efficiency starts with an overview of currently used methods for PPP [i.e., d-exponent, wireline logs (sonic, resistivity)) and an introduction to the MSE theory. Then the new methodology, called DEMSE method, is presented and illustrated with an example from a well deepwater Gulf of Mexico, where it is compared to the PPP results derived from sonic logging and d-exponent. The authors show that pore-pressure estimates from the DEMSE method “generally agree in magnitude and trend” with the PPP derived from sonic logs. They also emphasize the importance of downhole drilling data, especially for torque. If such data is available, the energy-based DEMSE method should be an improvement when compared with the d-exponent approach, which considers weight-on-bit (WOB) only. A new alternative I recommend trying (mainly computation = relatively low cost involved) for after-drilling reviews or to derive a more substantiated PPP for new wells planned in the vicinity.

Our fourth article in this issue discusses an important aspect of deepwater well control: what to expect from a gas influx coming up your drilling riser. Some respective insights are provided therein.

In Mitigating Gas-in-Riser Rapid Unloading for Deepwater-Well Control, the authors first verify their dynamic simulation model by comparing its results with published data from an actual field test in 1,200 ft (365 m) water depth. To control unloading, it is proposed to close in the riser (8,000 ft/2440 m water depth modeled) and the associated water hammer effect is investigated. Then, it is studied how to circulate the gas influx out with surface backpressure applied. Dual-gradient and conventional drilling with water-based mud (WBM) and oil-based mud (OBM) are covered, but influx volumes >10 bbl (1,59 m3) with OBM should be studied further. The simulations (30 bbl/4,77 m 3 influx in the example) show that water hammer is not a concern if the riser is shut in over >10 seconds. For a constant pump rate, OBM leads to higher outflow rates on surface (gas solubility) compared to WBM, and the latter is in general easier to handle. Dual-gradient and conventional drilling both result in similar trends and outflow rates. The authors clearly recommend applying backpressure at surface for safe riser gas handling, but OBM could require pump rate reductions after the gas comes out of solution. 

If you are concerned with the structural integrity of subsea wells, our next paper is for you, because here we offer a useful description of casing settlement estimations for a well offshore West Africa.

The authors of Angola Cameia Development Casing-Settlement Calculations begin with a literature survey about how axial forces and displacements are described for beams, piles, and elastic foundations. They introduce the input parameters required for the relevant equations (finite element analysis), continue with a presentation of the investigated loading stages (upper casing installation, hanging-off the next (lower) casing, installing the tree/BOP to an uncemented string, and installing the tree/BOP to a cemented string), and discuss the influence of foundation (sediment layers and cement) moduli. The calculated, worst-case settlement of 0.5 m (1.6 ft) for a structural casing sticking up 3 m (9.84 ft) above mudline actually did not occur, as visually confirmed by remotely operated vehicle. Personally, I like the application of “classical” mechanical/civil engineering fundamentals to assess a casing’s settling risk, and would hope that is not only a consequence of (my) age, but that you can appreciate it, too.

Optimizing (water-based) mud formulations for shale inhibition is a constant challenge for many of us. If you are interested in some insights into what the addition of silica-nanoparticles (nanosilicas) could do for you in that respect, please read on.   

Functionalized Nanosilicas as Shale Inhibitors in Water-Based Drilling Fluids starts with an overview about shale inhibiting additives commonly used in WBM, often associated with high pH values (up to 12.5) or chloride concentrations posing challenges for disposal (i.e., onshore USA). Subsequently the experiments performed with four WBM formulations, each with fresh water and (“artificial”) seawater, and two different shales (Mancos, with ~10 wt% illite/smectite and Pierre II with ~28 wt% illite/smectite) are presented, followed by a discussion of the respective results. The authors conclude that synergetic effects for shale inhibition between polymers and the investigated nanosilica types are observed, and that nanosilicas show a better inhibition performance in seawater vs. fresh water. The required pH-values can be reduced to 8.5 to 10. Reductions in chloride concentration (i.e., KCl) could also become a possibility, but would need to be confirmed by further studies.    

Our next article is highly recommended to all colleagues concerned with the definition of laboratory test series for drilling, cementing, or fracturing-fluid optimization because it describes how computation—pertaining here to machine-learning algorithms [i.e., Gaussian-process regression (GPR), also known as Kriging] and artificial neural networks (ANN)—could help to reduce the actual experimental scope to be executed. Certainly something to consider in times of increased cost pressures.

In Intelligent Tool To Design Drilling, Spacer, Cement Slurry, and Fracturing Fluids by Use of Machine-Learning Algorithms, the authors first share the motivation for their work (test scope, hence cost, reduction, and independence from staff’s personal experience levels, “trial and error”), introduce machine-learning methods for nonlinear regression (with details in the appendix), share the pros and cons of those, and illustrate the approach with an example of a cementing spacer fluid design. They clearly recommend GPR because of advantages over ANN (i.e., no a priori assumptions required for the regression functions, inherent provision of estimation accuracy as “added benefit”). Therefore, if you have sufficient meaningful “training data” available, it would probably be an effort to define and train the respective GPR algorithms at the start, but once established, you should benefit from those for all related fluid analyses in the future. 

That’s it for this second issue in 2017. On behalf of the entire Editorial Review Committee, I thank you for your continued support of SPE Drilling & Completion.

Christoph Zerbst, SPE Drill & Compl Executive Editor;
Petroleum Development Oman