Technology Focus In recent years, I have not seen any significant changes in the systems used for sand control, and I have been wondering why. It may have more to do with our confidence and comfort in our current approaches than with not having any Earth- shattering new ideas. The phrase “necessity is the mother of invention” is probably valid in this case. The necessity has been evident in the ways that our industry has expanded the capabilities of the existing systems that we already use successfully. These expansions are in a great many areas—temperature, pressure, size, length, materials used, modeling capabilities, reliability, complexity, and more. I think it is safe to say that the engineers and companies involved, in either building or using sand-control systems, have made significant strides and have added critical learnings to our industry. I expect that we will have another revolution or revelation in sand management or sand control. As an example, development of unconventional and tight-rock assets is causing our industry to develop novel approaches to the tools and the pumping processes that are used. I am already seeing some of those ideas showing up in the modifications to our proven sand-control systems. In line with this broader scope of sand-control systems and methods, this feature, previously called Sand Management and Frac Pack, is being renamed. The new name is Sand Management and Sand Control. This new name recognizes that there is a range of systems and approaches that continue to be used by our industry as we work to provide the best approach for each asset that we develop. I am confident that you, our readers, will agree with this broader scope. The papers selected for this feature focus on some remarkable adaptations based on standard systems and problems that we have faced for years. These papers highlight multizone applications, erosion tolerance, and shale stability and control. All of these are dealt with every day, in various ways, by completion engineers around the world. JPT Recommended additional reading at OnePetro: www.onepetro.org. OTC 24884 Single-Trip Multizone Gravel-Packing Case History Improves Anticipated Production From the Berantai Field by E. Damasena, Petrofac Energy Development, et al. SPE 169440 Design and Validation of an Improved Shunt-Tube System by A. Bonner, Halliburton, et al. SPE 168636 Evolution of Frac-Pack Design and Completion Procedures for High-Permeability Gas Wells in Subsea Service by Vibhas J. Pandey, ConocoPhillips, et al.

Sand control risks, costs, and alternatives are significant factors in the planning phase of a field development. A mechanical earth model (MEM) which includes in-situ stress and rock strength should be constructed and used to evaluate potential for rock failure during production. Fully integrating and calibrating strength, stress, and failure models is crucial to correctly characterize sanding potential. The MEM for the Tombua-Landana Development in deepwater Block 14, offshore Angola will be presented to illustrate the methodology of this approach. In this field case: In addition to conventional triaxial core tests which provide rock strength in a limited number of samples, core scratch test data was used to establish continuous rock strength over most cored intervals. A log based neural network was used to extend the rock strength information to the non-cored intervals. Comparison between log, scratch test, and triaxial core test strengths will be presented. Acoustics based stress computations are calibrated to leak-off test and mini-frac stress measurements. Calibration of failure models to both drilling wellbore stability and completion safe drawdown pressures verifies the validity of the mechanical earth model. Both openhole and cased and perforated sanding potential were evaluated using the fully integrated earth model. Oriented perforations have the potential to significantly reduce the risk of sanding in completions without gravel packs or screens. Introduction The Tombua-Landana field is located in Block 14, offshore Angola with water depth approximately 800 to 1,300 ft. The Tombua and Landana central reservoirs are composed of high quality sands deposited in a deepwater slope valley environment on the northwestern flank of the Congo River Fan. The producing reservoirs are Lower Miocene CN3 in age and form moderately thick successions of sand sequences. The overall Tombua-Landana depositional system comprises a series of large, stacked, offset channels. Tombua-Landana development is the third major field development in Angola's Block 14, after Kuito and Benguela-Belize-Lobito-Tomboco. It is a major capital project that will have expenditures in the order of billion dollars for all components. Geomechanical modeling played an important role during the early phase of field development planning. Completion decisions are aided by an accurate assessment of sanding characteristics of various well designs. A MEM was constructed to estimate sanding potential for the Tombua-Landana field. This MEM was then calibrated to field data. An overview of the building of the Tombua-Landana MEM is presented in this paper. Building a Mechanical Earth Model (MEM) A MEM consists of in-situ stresses and rock strength linked with a failure model. These are all calibrated to wellbore observations of rock failure behavior. Sand production results from rock failure caused by the imbalance between the local stress state near the wellbore and rock strength. In this section, the process and method of determining in-situ stresses and rock strengths will be shown. It will also be shown that the sand production predicted using the in-situ stresses and rock strengths matches the core tests, well test results, and drilling performance. Therefore, the in-situ stresses, rock strengths, and failure model are most likely valid and can be used for the field sanding potential analysis. Earth In-Situ Stresses The in-situ stress magnitudes and orientations can affect the sanding potential of wells. In most cases, principal in-situ stresses can be expressed as:Overburden stressMaximum horizontal stress (SHmax)Minimum horizontal stress (Shmin) The overburden stress is in the vertical direction and is generally, as in this case, calculated by vertically integrating the density log. Two horizontal stresses are the two principle stresses perpendicular to each other on a horizontal plane. The larger horizontal stress is called maximum horizontal stress and the lesser one is called minimum horizontal stress.

Cased Hole Frac Packs (CHFP) are among the preferred completion strategies for deepwater production wells due to sand production concerns and the high cost associated with subsea interventions. An acid stimulation treatment is usually conducted prior to the main frac operation in order to clean-up some of the perforation debris (including powdered metals from shaped charges) and residual fluid loss control (FLC) materials which can be a significant source of formation damage and plugging of screens and other wellbore jewelry. A few studies have also considered the technical and economical benefits of adding a scale inhibitor during the completion operation (Fitzgerald and Cowie, 2008;Lungwitz et al. 2007;Martins et al., 1992;Vetter et. al., 1988). The challenges associated with adding a scale inhibitor to the frac fluids are widely recognized, and some alternatives such as the use of encapsulated scale inhibitors and scale inhibitor-impregnated proppant have been proposed (Powell et al. 1995;Fitzgerald and Cowie, 2008). The addition of scale inhibitor to the early stages of the frac operation has also been explored (Maschio et al., 2007), but the temperature ranges evaluated have been rather limited. The purpose of this work is thus twofold: 1) To evaluate the effectiveness of two acid suites to clean-up Zn powder damage typically encountered during perforations with metal shaped charges, and 2) To qualify the incorporation of an acid pentaphosphonate scale inhibitor to the pre-frac acid in frac treatments targeting high temperature (up to 300 o F) deepwater subsea wells. This paper describes in detail the laboratory qualification of the acid suite, and the acid / scale inhibitor combination treatment. Performance field data on the treatments is the subject of subsequent publications. A HCl / organic acid suite with a novel, three-component corrosion inhibitor package was developed to clean-up Znrelated damage without compromising rock strength or corrosion protection at high temperatures (up to 300 o F). In addition, the combination treatment consisting of scale inhibitor treated acid and overflush brine was found to be compatible with reservoir and wellbore fluids in the field of interest. The treatment was found to be non-damaging in high permeability (> 1000 md) Y core samples. Strong wettability changes and up to 50% reduction in permeability to oil were observed in low permeability X core samples. Further improvement of the acid / scale inhibitor combination treatment for low permeability reservoirs is also discussed. The results from this study contribute to a better understanding of scale management in high temperature subsea wells.Oxidizer breaker 5gal/Mgal

Technology Focus Ours is a cyclical business. Those involved in well work (i.e., drilling, completions, and workovers) are currently feeling the effects of reduced activity. Overall, I think those involved with drilling activities are affected most. Those involved with completions and workovers are affected to a lesser degree simply because of the opportunity to optimize. Whether that optimization occurs as part of improvements to the completions processes or workover processes, similar skills are needed. For operators, the most cost-efficient barrel we produce is the next one that is produced after we optimize an already-producing well. It is the operator’s responsibility to find ways to optimize production. This is often achieved through interventions or recompletions. In challenging financial times (as with technical challenges), we need to be flexible enough to refocus our efforts in new and often uncomfortable ways. Each of the papers I have selected provides examples of how to do just that: challenge the status quo. Many of us have been so busy chasing the next well and the upcoming job that our skills in the area of optimizing our completions may have become a little rusty. Now is a great time to knock off that rust and revisit our best-laid plans. One way may be for you, alone or with your peers, to review the wells completed in your current project, or a subset of those wells, and figure out what went right and what went wrong. This deep dive into the details will often pay significant dividends in terms of understanding your current project. With that deeper understanding, you can develop an improvement plan for your current project or for your next project. The improvements required are often difficult to achieve. Operators, particularly those with inventory already on the ground and pressure to use that inventory, might not be comfortable with changing their approach. However, a significant change in direction might be exactly what is needed. In these challenging and uncomfortable times, I encourage each of you to challenge yourself and your peers to be uncomfortable and at least evaluate approaches that your organization might not have used historically. Those unfamiliar approaches might just be the right answer. The papers selected for this feature provide you, the reader, with the opportunity to learn from the efforts of others. I hope that you will be able to use one or more of their approaches to improve the economics in your assets. JPT   Recommended additional reading at OnePetro: www.onepetro.org. SPE 170278 Successful Placement of an Advancing Sand- and Fines-Control Chemical as a Remedial Sand Control Using Subsea Flowlines From an FPSO by Michele Piemontese, Eni, et al. SPE 174240 Chemical Sand Consolidation as a Failed-Gravel-Pack Sand-Control Remediation in Handil Field, Indonesia by Antus Mahardhini, Total, et al. SPE 174407 A Successful Post- Completion Sand-Control Method Used in Thermal-Enhanced-Oil-Recovery Operations at the Kern River Field in Bakersfield, California by Spencer Franks, Chevron, et al.

Technology Focus I suppose that many of us are taking a deep breath just now. Many of us could be revisiting how we have been completing wells and what we might be able to improve. These improvement areas often involve some sort of trade-off between well deliverability and well/completion costs (in terms of equipment and rig time to deploy these various alternatives). I suspect that we all have been involved with completions where these two areas are debated. In my experience, it seems that much of our discussion revolves around what the various participants “feel” is the best approach. Much of the decision eventually hinges on what we will do in the short term (deployment) rather than in the long term (deliverability). The reason is, in my opinion, that we are fairly sure about the near-term items (related to cost) but often very uncertain about the longer-term items (deliverability as a result of how well we deployed the lower completion). Why is it that many of our completion quality decisions are focused on cost and not deliverability? I can think of two primary reasons: (a) We lack the metrics to support our decisions and (b) we do not have consistent practices (e.g., laboratory and design work, deployment processes) across our wells to allow us to compare our results. I suspect that you can think of others. Both of these areas offer improvement opportunities. For those of us who have a robust set of metrics to evaluate our overall sand-control planning and deployment process, if the preparation work (e.g., core testing, compatibility testing, equipment selection) is not carried out in a consistent fashion, the variation in results as depicted in our metrics would not lead us to a specific course for improvement because the variation from well to well might simply be explained away by the differences in planning and execution. Given the preceding idea, could the development of consistent practices be a critical first step on our journey toward achieving improvements in completion quality? The list of those practices that we should carry out in a consistent manner is quite long. For sand-control applications, we could start with those activities that occur early in the design process. After reviewing the many high-quality technical papers written over the past year, I have found a few that I think offer a good place for you to start your journey toward consistency. The three summarized papers are all related to the selection of proppant and screens in your sand-control completions. I am not promoting any one of these papers over the others. However, I am suggesting that whatever your organization does in this area, your organization should do it consistently. You may find your organization’s new, preferred approach to proppant and screen selection in one or more of the presented articles. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 178966 Sand-Retention Testing: Reservoir Sand or Simulated Sand—Does It Matter? by Tracey Ballard, Weatherford, et al. SPE 179036 Sand-Screen Design and Optimization for Horizontal Wells Using Reservoir Grain-Size-Distribution Mapping by Mahdi Mahmoudi, University of Alberta, et al.