Executive Summary

I would like to start this summary with a cordial “Thank you!” to our outgoing Associate Editor Alexander Crabtree (Hess/Consultant), who dedicated his industrywide recognized expertise, together with vast experience, energy, and time, over several years to identify papers of interest and to develop them into quality publications for SPEDC! His achievements for our journal deserve even more respect knowing that he also serves on the JPT Editorial Committee.

Fortunately, even in times like these, we have colleagues who are prepared to volunteer for the benefit of our readers. Therefore, I am pleased to welcome Andrew Zheng (Schlumberger), who did not hesitate to agree supporting us in the Editorial Review Committee of SPEDC as Associate Editor, especially with (but not limited to) his expertise in managed and underbalanced pressure drilling (MPD/UBD).

Offering a formal—and relatively easy—process for our authors to appeal an editor’s decision is one of the (many) distinctive features of SPE’s peer-reviewed publications (one that is absent with most “competitors”). Although we have had only two appeals within the last 3 years for SPEDC, it seems to be more commonly (ab-)used with some of our sister journals. And because every appeal creates much more work (to be handled by a diminished group of staff in the SPE offices) than a “normal” manuscript submission, I would like to inform you about ongoing discussions to discontinue the established appeal process. Please note that this is a “work in progress” and not yet finalized. Therefore, should you have strong opinions about the existing appeal option, I certainly would like to read them (my e-mail address is shown at the bottom).

At the end of July 2018, Associate Editor (and former Executive Editor) Curtis Cheatham held an SPE Technical Reviewer Webinar, and the number of registrations for this event (>250!) was very encouraging. If you are an expert in your field and interested in becoming a technical reviewer for SPE’s peer-reviewed journals, please note that attendance of this webinar (it has been recorded for future reference) is one of the mandatory requirements along with years of experience and number of your own peer-reviewed publications.

Now, on to this issue’s papers, which will hopefully provide some helpful thoughts for the various assets and projects you are looking after.


For those of you planning deep, tight gas field developments while assuming that any risk of sand production will be negligible because of the formation’s strength and tightness, our first article could serve as a kind of “eye opener.” Experiences from a high-pressure/high-temperature (HP/HT) tight gas field onshore China, initially thought to produce sand-free based on formation unconfined-compressive-strength (UCS) values greater than 100 MPa (~14,500 psi), are shared, together with the analyses performed and solutions identified after erosion from produced sand had been observed relatively soon after production startup.

In Analyzing Unexpected Sanding Issues in the High-Pressure/High-Temperature, Tight-Sandstone Keshen Gas Reservoir, Western China, after a field description, the work flow developed to identify the sanding mechanism (literature review, field-data collection, particle-transport simulation, geomechanical assessment of perforation-tunnel stability) is presented. The resulting sand-management strategy for existing wells includes flow velocity and drawdown reduction (bean-back and/or additional perforations), restimulation and improved sand monitoring, while new wells will be designed considering the critical drawdown limit established in the study. It is emphasized that sanding cannot completely be controlled by the applied pressure drawdown alone, and flow velocity needs to be considered independently. I am grateful that the authors share their experiences, which will allow others to check if the conception that “hard rock never sands” is really justified in their circumstances, too.

Are you designing a critical explosive perforation job for a carbonate formation and looking for respective data to benchmark your predictions? Then our next paper is for you because it presents experimental results from shooting limestone targets (40×30×30-cm cubes) subjected to different stress states with shaped charges (14-g explosive weight, HMX) in a 5-in., 18-lbm/ft gun carrier, complemented by some tests in concrete as well as under (unstressed) surface conditions.

After a description of the polyaxial compressive test setup, the authors of Stress-Dependent Perforation in Carbonate Rocks: An Experimental Study share sample preparation and the outcome of the “design of experiment” exercise performed to reduce the number of actual tests to be conducted (to 28). All experiments were done with a sealed gun carrier to prevent explosive gases from immediate exhaust. The results are discussed especially under aspects such as effect of stresses or shot density [4 and 6 spf (13 and 20 spm)] on depth of penetration (DOP) and perforation entrance hole size. It is concluded that DOP is more controlled by the stresses normal to the perforation-tunnel axis than by the stress in shooting direction, and that subsequent charges penetrate deeper because targeting a zone already weakened by the first one fired. In my view, the results of these experiments are a welcome addition to publicly available data and helpful for the calibration of perforating-simulation software, for example.

Our next paper presents information especially relevant for all colleagues concerned with coiled-tubing (CT) fatigue prediction and monitoring, because it investigates the combined effect of cyclic plastic bending (at reel and gooseneck) and internal pressure on diametral growth and wall thinning (referred to as “ratcheting”). The algorithms applied for calculating this effect are compared to actual cyclic-bending test results under internal pressure.

Theoretical and Experimental Investigation of Coiled-Tubing Deformation Under Multiaxial Cyclic
first describes the algorithms developed based on the incremental plasticity theory (yield criterion, flow rule, and kinematic hardening rule using the principle of virtual-work), followed by the experimental setup (1½-in. CT with 80-ksi yield strength). Finally, the test results [48-in. bending radius with 5,000- and 750-psi (34.5- and 5.2-MPa) internal pressure, 72-in. bending radius with 5,000 psi) are compared with the numerical model predictions for outer diameter and wall thickness. The authors demonstrate that by incorporating the nonlinear geometrical relationship from Gellin (1980) and the A-F hardening rule (Armstrong and Frederick 1966) in their algorithms, a good correlation between predicted and measured CT-outer-diameter increase and wall-thickness reduction can be obtained for both, magnitude and trend. I regard it as a useful addition to our analytical “toolbox,” which can help to maximize run life of the CT strings deployed by focusing on the sections with the highest deformation risk from “ratcheting.”


For all of you responsible for well control (or annular pressure buildup later), our fourth paper covers a highly relevant topic—the behavior of synthetic-based mud (SBM) under pressure and temperature after a gas influx into the well. Therefore, pressure/volume/temperature (PVT) measurements on linear olefin/methane mixtures were conducted and also compared with available data for n-paraffin/methane and ester/methane mixtures.

Thermodynamic Behavior of Olefin/Methane Mixtures Applied to Synthetic-Drilling-Fluid Well Control
starts with a literature review, followed by a description of the test equipment and procedures. It further shares the experimental results for parameters like density, formation volume factor (FVF), and gas-solubility ratio dependent on pressure [up to 69 MPa (10,000 psi)], temperature [25 to 80°C (77 to 176°F)], and mixture composition (0.3 to 0.5 gas molar fraction), showing that the gas-solubility ratio is temperature independent for pressures less than 34 MPa (5,000 psi), while mixture density and FVF are temperature influenced over the whole pressure range investigated. From the comparison with other mixtures, the authors conclude that olefin/methane mixtures are more sensitive to pressure and temperature changes than n-paraffin/methane mixtures, and that methane is less soluble in olefin- compared with n-paraffin- and ester-based fluids, which should support earlier kick detection. I do support their recommendation of using these data to update well-control software (kick simulators) for an improved representation of SBM behavior downhole.

If you are interested in improving the integrity of casing connections (including the ones of solid expandable tubulars, SET), the following paper presents how brazing—as a technique to join dissimilar materials using a melted filler to achieve a metallurgical bond—could help in that respect. A prototype brazing system was built, and experiments conducted on 85/8-in. (L-80, BTC) and 95/8-in. (VM50 and P-110, SLIJ-II, TH513) casing connections with subsequent integrity testing under internal pressure [≤35 MPa (5,050 psi), Quadrants 1 and 2 of the von Mises ellipse].

In Improving Casing Integrity With Induction Brazing of Casing Connections, the authors share the motivation for their work (trouble with SET integrity), explain the temperature/torque/time (TTT) process applied, and the developed brazing system including its components (heating coil, cooling, power tong, controls). Steel-grade dependent-filler-material selection (applied as flame-spray coating offline) and the test results for 34 specimens are discussed. It is shown that leak-tight conventional and expandable casing connections can be obtained with the brazing process applied, and the TTT process graph is useful to assess connection quality (similar to a torque/turn graph). Future work is planned to include brazed-connection testing in all four von Mises quadrants. Because makeup time/joint is not so much longer, and the brazing-system prototype is certified (NEC Class I, Div. 1), I hope it can soon leave its “laboratory habitat” to be tested on an actual rig floor.

Underreaming a section is (almost) never an easy task, and our next paper shares the approach of one service provider to design a bottomhole assembly (BHA) addressing the following challenges: (1) enlarge the hole from 12¼ in. to 14½ in., (2) maintain azimuth while dropping from 61 to 35° inclination at 2°/100 ft, (3) consider mud losses (LCM vs. hydraulically activated tools) and differential sticking risk (contact area) in depleted formations, and (4) eliminate rathole to set the casing shoe as deep as possible.

Directional Control and Rathole Elimination While Underreaming Depleted Formations With a Rotary-Steerable System (RSS) explains the objectives to be met and the iterative process for BHA design [at-the-bit reamer (ABR) between bit and RSS (for rathole reaming after reaching TD), upper underreamer above LWD (for reaming while drilling), stabilizer placement]. The final BHA was analyzed for side forces, bending moments, vibration tendencies, and its effects on drilling hydraulics (i.e., cuttings transport, ECD vs. ROP). The actual drilling of the section went smooth, following the planned trajectory without local doglegs, no string vibration issues noticed, and the rathole could be reduced to 2.5 ft (0.75 m). The author concludes that proper BHA modeling allowed placing the ABR just above the bit, therefore avoiding a dedicated trip to open up the usual 85- to 135-ft rathole left with previous BHAs. In my opinion, another good example of how detailed engineering including drilling-hydraulics analysis (instead of trial and error) can help to identify solutions for achieving “more with less” (roundtrips).

Knowing the “consumed fatigue life” of a subsea wellhead (WH) system after the end of drilling operations is important to assess the feasibility of future well interventions. Therefore, respective guidelines have been developed by certifying agencies such as DNVGL. Our next paper investigates how including the well-temperature distribution into the (DNVGL) fatigue analysis can affect the calculated WH cyclic stresses and the estimated fatigue-damage rates over time considering two different top-of-cement (TOC) depths between conductor and surface casing.

Subsea Wellhead Life-Cycle-Fatigue Analysis and the Role of Well Temperature first provides a literature overview, then shares the motivation for the study and the selected analysis method (well-temperature, WH fatigue including local and global responses and fatigue-damage assessment). The numerical approach is illustrated with a North Sea example well and the results (load-to-stress curves, WH fatigue) are discussed, covering aspects of accumulated fatigue damage, thermal effects on load sharing, or thermally induced displacement of well components. The authors summarize that with the WH models tested, the assumed drilling operations and the S-N curves used, the estimated accumulated fatigue damage reduced when temperature effects were included, and the simulated fatigue damage for the WH with shallow TOC was more influenced by thermal effects than the one with deeper TOC. Because operational (thermal) history and WH system are different for each well, I certainly support their clear recommendation of a case-by-case analysis.

That’s it for this third issue in 2018. On behalf of the entire Editorial Review Committee, I thank you for your continued support of SPE Drilling & Completion.

Christoph Zerbst, Executive Editor SPE Drill & Compl,
Shell (christoph.c.zerbst@shell.com)