Field Development Costs Research Articles

A supervised machine learning model to select a cost-effective directional drilling tool

With the increased directional drilling activities in the oil and gas industry, combined with the digital revolution amongst all industry aspects, the need became high to optimize all planning and operational drilling activities. One important step in planning a directional well is to select a directional tool that can deliver the well in a cost-effective manner. Rotary steerable systems (RSS) and positive displacement mud motors (PDM) are the two widely used tools, each with distinct advantages: RSS excels in hole cleaning, sticking avoidance and hole quality in general, while PDM offers versatility and lower operating costs. This paper presents a series of machine learning (ML) models to automate the selection of the optimal directional tool based on offset well data. By processing lithology, directional, drilling performance, tripping and casing running data, the model predicts section time and cost for upcoming wells. Historical data from offset wells were split into training and testing sets and different ML algorithms were tested to choose the most accurate one. The XGBoost algorithm provided the most accurate predictions during testing, outperforming other algorithms. The beauty of the model is that it successfully accounted for variations in formation thicknesses and drilling environment and adjusts tool recommendations accordingly. Results show that no universal rule favors either RSS or PDM; rather, tool selection is highly dependent on well-specific factors. This data-driven approach reduces human bias, enhances decision-making, and could significantly lower field development costs, particularly in aggressive drilling campaigns.

HORIZONTAL WELL PERFORMANCE MODELLING USING PSEUDOWELL TECHNIQUE

The potential improvement of horizontal productivity has been recognized since mid 1950s, where horizontal well allows longer flow interval hence higher flow rate with lower pressure drawdown. Such remarkable productivity improvement has fascinated the great interest of petroleum industries around the world to fit the role of effective field development strategy. The objective is to reduce the overall cost of field development. In the case of offihore oil fields, the horizontal well drilling is desired to eliminate required number of vertical wells and utilizing of expensive sub-sea technology. The continuous development and application of horizontal well drilling technologies have been reported in many publications, Nowadays, the horizontal well drilling and completion with complex trajectory is possible. However, the costs required by horizontal well drilling and completion is still considerably more expensive than the vertical one. The future needs of horizontal well drilling tend to arise depending on the economical aspect by means the horizontal well productivity outweigh the incremental drilling and completion costs. An adequate method is required to estimate it's expected productivity to determine the economic feasibility. This paper proposes a horizontal well performance modeling by the concept of pseudowell technique.

Subsea field layout optimization (part III) --- the location-allocation problem of drilling sites

This study proposes an efficient method to optimize the subsea field layout with the aim of minimizing the subsea field development cost, based on the two methods introduced in Part I and Part II for solving the well trajectory planning problem and the location-allocation problem, i.e., 3D Dubins Curve method and Binary Linear Programming (BLP) method, respectively. The most complex part in subsea field layout optimization is essentially a location-allocation problem of drilling sites embedded with the well trajectory optimization. The full process of our method is clearly summarized in a flowchart. Abundant case studies with comparison to the existing results demonstrate the optimality and the flexibility of our method to solve practical subsea field layout optimization problems. In the cases studies, we also reveal how different user-defined cost items affect the optimal field layout. Details of implementing our method for a better performance is also discussed. This work is the third of a series of papers which systematically introduce an efficient method for subsea field layout optimization to minimize the development cost.

Subsea field layout optimization (Part I) – directional well trajectory planning based on 3D Dubins Curve

Directional well trajectory planning, which includes the optimization of the drilling site location and the trajectory between the drilling site to the completion interval, plays an important role in reducing subsea field development cost. The traditional well trajectory planning methods are based on the projected 2D profile of the wellbore trajectory with empirical knowledge or trial-and-error method to select a proper drilling site. In this study, we propose a new efficient optimization method based on the 3D Dubins curve, which has been widely used in autopilot for path planning but has never been mentioned in drilling industry. In short, we use gradient descent method to find the best drilling site location while adopting the 3D Dubins curve as the optimal wellbore trajectory to reach each completion interval so that the “1-site-n-wells” problem can be easily solved. Abundant case studies including both mathematically representative cases and the real practical field cases are conducted to demonstrate the feasibility and efficiency of our method. Wider application of our method for more complex situations are also discussed. This work is the first of a series of papers which systematically introduce an efficient method for subsea field layout optimization to minimize the development cost.

Real-Time Minimization of Mechanical Specific Energy with Multivariable Extremum Seeking

Drilling more efficiently and with less non-productive time (NPT) is one of the key enablers to reduce field development costs. In this work, we investigate the application of a data-driven optimization method called extremum seeking (ES) to achieve more efficient and safe drilling through automatic real-time minimization of the mechanical specific energy (MSE). The ES algorithm gathers information about the current downhole conditions by performing small tests with the applied weight on bit (WOB) and drill string rotational rate (RPM) while drilling and automatically implements optimization actions based on the test results. The ES method does not require an a priori model of the drilling process and can thus be applied even in instances when sufficiently accurate drilling models are not available. The proposed algorithm can handle various drilling constraints related to drilling dysfunctions and hardware limitations. The algorithm’s performance is demonstrated by simulations, where the algorithm successfully finds and maintains the optimal WOB and RPM while adhering to drilling constraints in various settings. The simulations show that the ES method is able to track changes in the optimal WOB and RPM corresponding to changes in the drilled formation. As demonstrated in the simulation scenarios, the overall improvements in rate of penetration (ROP) can be up to 20–170%, depending on the initial guess of the optimal WOB and RPM obtained from e.g., a drill-off test or a potentially inaccurate model. The presented algorithm is supplied with specific design choices and tuning considerations that facilitate its simple and efficient use in drilling applications.

Utilization of Steel-Making Dust in Drilling Fluids Formulations

Steelmaking is an energy-intensive process that generates considerable amounts of by-products and wastes, which often pose major environmental and economic challenges to the steel-making industry. One of these by-products is steel dust that is produced during the separation of impurities in the smelting and refining of metals in steel-making furnaces. In this study, electric arc furnace (EAF) dust has been evaluated as a potential, low-cost additive to increase the viscosity and weight of drilling muds. Currently, the cost of drilling operations typically accounts for 50 to 80% of the exploration costs and about 30 to 80% of the subsequent field development costs. Utilization of steelmaking waste in drilling fluids formulations is aimed to produce new and optimized water-based drilling formulations, which is expected to reduce the amount of bentonite and other viscosifier additives used in the drilling formulations. The results showed that in a typical water-based drilling fluid of 8.6 ppg (1030.51 kg/m3), the amount of standard drilling grade bentonite could be reduced by 30 wt.% with the addition of the proposed new additive to complete the required mud weight. The mixture proved to be stable with no phase separation.

Can high-resolution reprocessed data replace the traditional 2D high-resolution seismic data acquired for site surveys?

Can high-resolution reprocessed data replace the traditional 2D high-resolution seismic data acquired for site surveys?

ОЦЕНКА СТОИМОСТИ ЗОЛОТОРУДНЫХ МЕСТОРОЖДЕНИЙ С УЧЕТОМ ВЕЛИЧИНЫ КАПИТАЛЬНЫХ ЗАТРАТ

В статье рассматриваются вопросы геолого-экономической и стоимостной оценки месторождений полезных ископаемых. Существующие методики обладают рядом преимуществ и недостатков, но строятся на единых показателях оценки без учета особенностей каждого месторождения. Автором предлагается методика, позволяющая быстро и просто определить стоимость месторождения золота на основе данных рудных запасов. Предлагаемая методика позволяет определить реальную стоимость месторождения золота с учетом включения затрат на развитие и освоение месторождения, а также рассчитать предельную (рекомендуемую) величину инвестиций по сделке. Кроме того, методика дает возможность оценить вклад запасов и ресурсов минерального сырья в общую рыночную стоимость горно-добывающего предприятия.Методика основана на анализе эмпирического материала, в качестве которого послужили факты реальных сделок покупки месторождений золота (и сопутствующих металлов) компанией Polymetal International plc. В результате статистического исследования получена формула для определения предельной стоимости месторождения с учетом включения затрат на развитие и освоение месторождения. Сопоставление реальной стоимости месторождений, определенной по результатам сделок с прогнозными значениями, показывает довольно высокую сходимость (R = 0,97). Основную ошибку в уравнения прогноза вносит недоучет факторов географической позиции объектов, инфраструктуры и наличия имущественного комплекса. Проверка методики на трех примерах сделок по приобретениям золотых активов компанией Polymetal International plc показала хорошую сходимость с реальной ценой сделок.

With New Rig Software, Automated Drilling is Easier To Embrace

Last summer, while being moved from one well pad to the next, a rig in the Delaware Basin of Texas was updated with some new software. It took 11 hours to complete, and after the rig was powered back up, it went on to drill the vertical section of a horizontal well almost 3 days ahead of schedule. Aside from boasting an impressive stat line, that well represents an important milestone for National Oilwell Varco (NOV) because it is the first to be drilled using the company’s closed-loop automated drilling system in conjunction with a recently launched rig operating system, which the company technically refers to as a process automation system. NOV is telling customers that this technology not only lowers the cost of field development, but delivers higher quality and straighter wellbores through its consistent performance. That automated program in Texas has concluded, but the combined technology package is now being used to drill shale wells on four rigs in the US and one in Canada. There are 16 separate orders for the new process system. These contracts for NOV follow more than 5 years spent using the hardware kit, which includes wired-pipe and a weight-on-bit controller, to drill through more than 2.5 million ft of conventional and unconventional formations. Going forward, the oilfield technology developer is offering a more complete product: automation controlled by highly capable software. This integration means that the digitally connected surface and subsurface machines working on an automated rig now have a digital driller to take orders from. “Our mantra is that the rig of the future is here today—just add software,” remarked Tony Pink, the vice president of strategic sales at NOV. Pink has been involved in the automation initiative at NOV since its genesis and coauthored a recently published technical paper (SPE/IADC 184694) detailing the Texas project that it carried out with Calgary-based Precision Drilling and an unnamed oil and gas explorer. He described the tandem of NOV’s automated hardware and software as “a sophisticated autopilot for rigs” that takes many routine tasks out of the driller’s hands—literally. With the process system in control, drillers can lay off the joystick, stop pressing buttons, and also quit staring at screens in order to maintain their drilling direction.

Stochastic optimization of hydraulic fracture and horizontal well parameters in shale gas reservoirs

Multistage hydraulic fracturing is one of the most important techniques in the successful exploitation and development of shale gas reservoirs. Most unconventional reservoirs rely on multistage hydraulic fracturing for commercial success. This success is accomplished by drilling horizontal well of appropriate length and creating transverse hydraulic fractures in stages across the well. Shale-gas reservoir's contact with the horizontal well bore is improved by using optimal well length, optimal fracture conductivity, optimum fracture length and optimum number of fracture stages. Because multistage fracturing of long horizontal wells increase the cost of field development, the economics of field development can be improved by using global optimization algorithms to estimate the optimum values of these operational parameters. In shale gas reservoirs, hydraulic fracture parameters such as fracture half-length, amount of proppant and fracture spacing should be optimized to maximize the net present value (NPV).In this work, differential evolution (DE) is implemented on a more realistic LGR-based shale gas reservoir simulation model. The objective is to maximize the net present value by optimizing hydraulic fracturing parameters and horizontal well length. Results obtained indicate that significant increase in NPV can be realized by using the optimization algorithm to estimate the operational parameters of hydraulic fracturing process in shale gas reservoirs.

Minimum economic field size estimation and its role in exploration project risks assessment: evaluation of different methodologies

The E&P business is most often rife with risks and uncertainties. The capability of recognizing and quantifying these uncertainties and associated risks are the key to success. For consistent exploration project risk analysis, a standard discounted cash-flow approach, combining the geological risk, Minimum Economic Field Size (MEFS), resource size distribution, development cost, rate streams, commodity price, discount rate and cash flow estimation, has been used. This task requires highly skilled geoscientists, reservoir, facility, drilling engineers and economists to estimate field development costs, generate the economic indicator to rank the exploratory prospects’ potential success and to support the informed business investment decisions. The ‘Exploration Success’ contains two main variables: (1) Probability of geologic success (Pg), and (2) Probability of economic success (Pe). To remove sub-economic volumes from the volumetric distribution, the industry uses the estimation of minimum required (break-even) resources for the full project life-cycle, considering the most likely development scenario in exploration projects. For appraisal and pre-development projects, the minimum required resources are used to benchmark the confidence level of already discovered resources with their chance of success to be economically viable. Despite several contributions made in the past and available in the literature, to the best of the author’s knowledge, most often a deterministic MEFS value is being used for the exploration project risk assessment. This single MEFS value does not allow for the capturing of the risks associated with the different input parameters uncertainties, which are used for the MEFS estimation. Therefore, in this paper, we are reviewing and systematically describing the appropriate MEFS estimation methodology. The influence of key parameters has been analysed through an example, using different MEFS methods, to demonstrate their importance for MEFS estimation. The comparison of results allows clear judgmental insights into the problem and its related uncertainties, understanding and quantifying the exploration risks and hence the chance of overall economic success.

Establishing minimum economic field size and analyzing its role in exploration-project risks assessment: A practical approach

The upstream E&P industry is one of the riskiest businesses in which to invest and is dominated by different types of uncertainties: political, economic, social, and technical. Many factors can lead to optimistic or pessimistic risk assessment. Overestimation, underestimation, misidentifying critical risks, overselling projects, and underselling projects are some of the problems. For consistent risk analysis of exploration projects, a systematic approach is used that includes geologic risk, minimum economic field size (MEFS), resource-size distribution, development cost, rate streams, commodity price, and discount rate. This approach requires highly skilled geoscientists and reservoir, facility, and drilling engineers to estimate field-development costs, generate the economic indicator, rank the exploratory prospects' potential success, and support the business decisions. The definition of “exploration success” contains two main variables: (1) probability of geologic success (Pg) and (2) probability of economic success (Pe). To remove the risk of subeconomic volumes from the volumetric distribution, the industry uses the estimation of minimum required resources for the full project life cycle, considering the most likely development scenario. An effort is made to describe the appropriate MEFS estimation methodology, which is an essential component for consistent exploratory-project risk analysis. The influence of key parameters on MEFS estimation, including some illustrative examples, also are analyzed to demonstrate the criticality of MEFS estimation and its impact on exploratory-prospect risk assessment and to achieve an overall economic success.

Seismic permanent reservoir monitoring (PRM) – A growing market

Offshore Seismic Permanent Reservoir Monitoring (commonly known as PRM) is a seabed-based technology that is becoming part of the reservoir engineer’s toolkit for practising better management of oil and gas fields. In its most commonly practised form, PRM involves conducting 3D seismic surveys at repeatable periods, generally somewhere between six months and two years. The time interval between surveys may be variable, and depends on the specifics of the reservoir being monitored. It has been demonstrated to be a technical success because, as fluids are injected and/or produced from a field, the seismic data change in response to the changes in the reservoir. The field implementation of PRM has now become a major geoscience and engineering activity yielding tangible results. This paper is an attempt to present an overview, facts, and opinions that will be of use to engineers and geoscientists who are interested in what has been done, and what may be done, in the use of seismic permanent reservoir monitoring, or oilfield surveillance. The PRM market appears to be on an upswing, but it remains to be seen if that upswing continues. There are several reasons that have tempered the adoption of this technology. One is that it has been difficult to determine and publicize the cost-effectiveness of PRM. While upfront costs are relatively large compared to many geological and geophysical activities, they are not large when compared to overall field development, optimization, and maintenance costs. Companies are now taking a more realistic look at the ultimate value derived from PRM due to the growing number of published benefits versus cost. The second moderating reason emphasized here is the number of stakeholders, with a wide variety of technical expertise, perspectives, objectives, and motivations, which must be involved in approving and executing such a project. This situation is being addressed as more corporate leaders are made aware of how PRM may address, in addition to production and operational needs, a number of health, safety, and environmental (HSE) concerns, broadening the interested constituent base within operating companies, and further establishing the benefits of PRM. There are currently 13 installed PRM projects, with the longest-running (Valhall) having been operating since 2003. The high-quality seismic data obtained from these projects are capable of showing very small changes in seismic amplitude and/or travel time that result from changes in the reservoir and its contents, such as fluid type, saturation, and pressure. The seismic systems themselves have also become the vehicle to integrate other measurements at the seafloor, such as temperature, water chemistry, or small changes in seafloor topography – all parameters that may have HSE implications. The growing importance of this oilfield surveillance approach will ultimately result in a variety of engineers collaborating not only with geoscientists, but also with other departments within the corporation such as quality control and HSE. As shown by the technical and economic successes of at least two projects (Valhall and BC10), the appropriate use of a PRM system significantly increases recovery, production rates, and operational efficiency, and reduces reservoir management costs (Chen et al., 2015; Barkved, 2012; Caldwell, 2009).

Incident detection and isolation in drilling using analytical redundancy relations

Early diagnosis of incidents that could delay or endanger a drilling operation for oil or gas is essential to limit field development costs. Warnings about downhole incidents should come early enough to allow intervention before it develops to a threat, but this is difficult, since false alarms must be avoided. This paper employs model-based diagnosis using analytical redundancy relations to obtain residuals which are affected differently by the different incidents. Residuals are found to be non-Gaussian – they follow a multivariate t-distribution – hence, a dedicated generalized likelihood ratio test is applied for change detection. Data from a 1400 m horizontal flow loop test facility is used to assess the diagnosis method. Diagnosis properties of the method are investigated assuming either with available downhole pressure sensors through wired drill pipe or with only topside measurements available. In the latter case, isolation capability is shown to be reduced to group-wise isolation, but the method would still detect all serious events with the prescribed false alarm probability.

Diffraction imaging in fractured carbonates and unconventional shales

Diffraction imaging is recognized as a new approach to image small-scale fractures in shale and carbonate reservoirs. By identifying the areas with increased natural fracture density, reservoir engineers can design an optimal well placement program that targets the sweet spots (areas with increased production), and minimizes the total number of wells used for a prospective area. High-resolution imaging of the small-scale fractures in shale reservoirs such as Eagle Ford, Bakken, Utica, and Woodbine in the US, and Horn River, Montney, and Utica in Canada improves the prospect characterization and predrill assessment of the geologic conditions, improves the production and recovery efficiency, reduces field development cost, and decreases the environmental impact of developing the field by using fewer wells to optimally produce the reservoir. We evaluated several field data examples using a method of obtaining images of diffractors using specularity filtering that could be performed in depth and time migration. Provided that a good migration velocity was available, we used the deviation of ray scattering from Snell’s law to attenuate reflection energy in the migrated image. The resulting diffraction images reveal much of the structural detail that was previously obscured by reflection energy.

Diffraction imaging of the Eagle Ford shale

Diffraction imaging is a novel technology that uses diffractions to image very small subsurface elements. Diffraction imaging may: (1) improve prospect characterization and pre-drill assessment of the local geology; (2) improve production and recovery efficiency; (3) reduce field development cost; and (4) decrease environmental impact. Field development may be accomplished with fewer wells to optimally produce the reservoir using high-resolution images of small-scale fractures in shale or carbonate intervals. Standard approaches to obtain high-resolution information, such as coherency analysis and structure-oriented filters, derive attributes from stacked, migrated images. Diffraction imaging, in comparison, acts on the pre-stack data, and has the potential to focus super-resolution structural information. Diffraction images can be used as a complement to the structural images produced by conventional reflection imaging techniques, by emphasizing small-scale structural elements that are difficult to interpret on a conventional depth image. An efficient way to obtain diffraction images is to first separate the migration events according to the value of the specularity angle, in a similar way to offset gathers, and subsequent post-stack processing. The high-resolution potential is demonstrated by the diffraction images from the Kenedy 3D survey over the Eagle Ford shale, which show much more detail than conventional depth migration or coherence.

New-Generation Drillpipes Enhance Extended-Reach Drilling in South China Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16798, ’New Generation of Aluminum Drillpipes Enhanced ERD Performances in the Huizhou Field, South China Sea,’ by W. Scaruffi, E. Cristofanelli, S. Yu, and A. Trocchia, Eni China, and C. Molaschi and A. Merlo, Eni, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission. This paper presents the results of a performance-improvement effort in extended-reach drilling (ERD) in three campaigns in the Huizhou HZ 25-4 oil field in the South China Sea. The new methodological approach and the deployment of new-generation aluminum drillpipes (ADPs) have resulted in a reduction of drilling risk and increased cost savings. Introduction ERD allows the reduction of the number of drilling sites, including offshore platforms, artificial islands, or other structures, and allows better control of total field-development costs. In addition, ERD technology makes it possible to reach reservoirs located at a considerable distance offshore, reducing the environmental impact of a wellsite. ERD operations are gaining momentum in the industry because they allow reserves exploitation previously considered too expensive when using conventional drilling methods. In addition, ERD techniques increase singlewell production by enlarging the drainage area. Because of their lighter weight when compared with steel drillpipes (SDPs), the use of ADP is a key solution for drilling extended- reach wells for the following reasons: A reduction in operating costs of approximately 10–20% (including savings in rig-capacity upgrade costs, transportation and energy costs, time-hosting costs, and tool-joint/casing-wear costs). An increase in the horizontal deviation of wells of approximately 10–30% (reduced torque-and-drag effect, less pressure drop, higher buckling resistance). Heightened reserves and production growth. A reduction in operative risk. Comparison of ADPs and SDPs Eni E&P first considered ADPs in July 2003, during the proposal and approval of a research-and-development project.

Gazprom vs. other Russian gas producers: The evolution of the Russian gas sector

The non-Gazprom gas producers (NGPs) doubled their share of the Russian domestic gas market between 2000 and 2010 and have continued growing since then. For several years especially Novatek expanded. More recently, Rosneft has emerged as a key player, not least through its purchase of TNK-BP. This article begins with an overview of the companies in the Russian gas sector, their resource bases and capacities, and subsequently examines whether differences in field development costs and export market access may make it rational for Gazprom to continue ceding market share to the NGPs. With rising costs of Gazprom's queue of greenfield developments, any delays in Gazprom's investment program may be compensated through increased NGP production. The article argues that the NGPs are ready to fill the gap, may be allowed to do so and are already increasing their market share in an increasingly competitive market. The stage may now be set for a continued gradual transformation of the Russian gas market, in which the interests of Gazprom and the NGPs may be complementary or may be pitted against each other, but those of the Russian Federation are in any case likely to be better fulfilled than in the past.

Integrated Completion Design for Horizontal Wells in Unconventional Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147120, ’An Integrated Approach To Design Completions for Horizontal Wells in Unconventional Reservoirs,’ by R. Jain, SPE, S. Syal, SPE, T. Long, SPE, and C. Wattenbarger, SPE, ExxonMobil, and I. Kosik, SPE, Imperial Oil Resources, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. An integrated workflow was tested for designing completions for a heavy-oil-recovery process that involves injection and production through the same wellbore. To capture the effect of variations or uncertainties in reservoir and fluid-flow characteristics over time, the transient effects are particularly important while analyzing the long-term performance for these types of completions. The proposed integrated workflow involves initial screening and selection of flow-restricting completions that can meet the desired injection and production performance on the basis of a detailed wellbore-hydraulics-modeling tool. Introduction Producing heavy oil and bitumen involves technologies such as cold mining for shallower resources or in-situ viscosity reduction. The cyclic solvent-based process involves alternating cycles of injecting a viscosity-reducing solvent into the reservoir followed by production of a mixture of heavy oil and solvent, with reduced viscosity, through the same wellbore. Many cyclic-process implementations are intended for use in horizontal wells. The completion design for such a process involves ensuring good solvent distribution into the reservoir during the injection phase to mobilize the resource along the entire wellbore and maximize the well length to reduce field-development cost. The process of injecting and producing from the same wellbore entails additional constraints on the completion design. One constraint is controlled injection distribution by use of flow-restriction devices such as orifices while maintaining a minimal pressure drop across the completion during the production phase. Another challenge results from the adverse mobility ratio of the solvent mixture and bitumen during the injection process, which could result in viscous fingering. This fingering can cause wide variations in the solvent injection and may cause an undesirable pressure distribution within the reservoir, which, in turn, may affect solvent placement. Predicting such differential injection or a thief zone is difficult because of the inherent nature of instabilities associated with the fingering process.

What can wave energy learn from offshore oil and gas?

This title may appear rather presumptuous in the light of the progress made by the leading wave energy devices. However, there may still be some useful lessons to be learnt from current 'offshore' practice, and there are certainly some awful warnings from the past. Wave energy devices and the marine structures used in oil and gas exploration as well as production share a common environment and both are subject to wave, wind and current loads, which may be evaluated with well-validated, albeit imperfect, tools. Both types of structure can be designed, analysed and fabricated using similar tools and technologies. They fulfil very different missions and are subject to different economic and performance requirements; hence 'offshore' design tools must be used appropriately in wave energy project and system design, and 'offshore' cost data should be adapted for 'wave' applications. This article reviews the similarities and differences between the fields and highlights the differing economic environments; offshore structures are typically a small to moderate component of field development cost, while wave power devices will dominate overall system cost. The typical 'offshore' design process is summarized and issues such as reliability-based design and design of not normally manned structures are addressed. Lessons learned from poor design in the past are discussed to highlight areas where care is needed, and wave energy-specific design areas are reviewed. Opportunities for innovation and optimization in wave energy project and device design are discussed; wave energy projects must ultimately compete on a level playing field with other routes to low CO₂ energy and/or energy efficiency. This article is a personal viewpoint and not an expression of a ConocoPhillips position.