Deepwater Field Research Articles

Experimental Demonstration of Shadow Zone Localization Using Deep Water Interference Patterns Measured by a Single Hydrophone

This paper discusses the frequency–range interference patterns of the sound field in deep water based on ray theory when the source and the receiver are near the sea surface. Approximate formulas of the frequency–range interference patterns in the shadow zone are derived. In the shadow zone, the sound intensity periodic structure is caused by the interference among the bottom-reflected, bottom–surface-reflected, surface–bottom–surface-reflected, and bottom–surface-reflected rays. The sound intensity changes according to the frequency with two cycles, which increase with the propagation range but decrease with the source and the receiver depths. As a result, the range and depth of the broadband sound source can be extracted from the interference cycles of the sound intensity using a single hydrophone. Interference patterns due to sea-surface broadband noise sources in the shadow zone have been observed in two deep-sea experiments in the South China Sea. Given the high signal-to-noise ratio, the interference cycles can be extracted manually from the time–frequency surfaces. Then, the availability of single hydrophone localization in the shadow zone is verified by experimental data. Compared with the conventional passive source localization methods, this method does not require broadband guide sources, precise seafloor acoustical parameters, or intensive computation of replica fields.

Technology Focus: Sand Management and Sand Control (October 2018)

Technology Focus Rig count and fracturing-crew activity are the pulse of the energy industry; as energy commodity prices increase, so do these vital numbers. During the past year, crude oil prices jumped 36% from $49.59/bbl (WTI) at the beginning of August 2017 to $67.68/bbl on 1 August 2018, with a maximum price of approximately $74/bbl in late June 2018. The price increase experienced during the past year has renewed investments in many plays. However, a long-term project, such as offshore deepwater field developments, would require a minimum sustainable oil price to be profitable. We, therefore, have not seen massive investment in developing challenging sand-prone fields that require large capital investment up front to complete wells with expensive and sophisticated sand-management and -control techniques. Perhaps the demand has not yet justified sustainable prices, leading some oil companies to rebalance capital allocation by increasing dividend payouts or stock repurchasing programs while waiting for the market forces to establish a price benchmark. In this respect, in the energy industry, no news very often is the best news; any geopolitical instability and tensions could cause oil prices to fluctuate abruptly and make operators feel uneasy about investing in capital-intensive projects. On the technology side, regardless of the oil price, demand persists for cost-saving and value-adding innovations and emerging technologies to bridge gaps in the existing technology portfolio for sand management and control. To stay in the know of the latest projects trending in the energy industry, read the featured papers and recommended additional reading and attend the upcoming 2018 SPE Annual Technical Conference and Exhibition 24–27 September in Dallas and the Asian Pacific Oil and Gas Conference 23–25 October in Brisbane, Australia. Recommended additional reading at OnePetro: www.onepetro.org. SPE 187237 Self-Assembling Nanoparticles: A Unique Method for Downhole Sand Consolidation by Rajendra Kalgaonkar, Saudi Aramco, et al. SPE 189491 Openhole Mechanical Packer With Eccentric Shunt-Tube Gravel-Pack Assembly Reduces CAPEX and Accelerates Production in Laombo Deepwater Development, Angola by J. Hernandez, Total, et al. SPE 189557 A Large-Scale Sand-Retention Test Facility for Evaluation and Selection of Optimal Standalone Sand Screen for Injection Wells in Thermal Operations by M. Mahmoudi, RGL Reservoir Management, et al.

Determination of In-Situ Reservoir Absolute Permeability Under Multiphase-Flow Conditions Using Transient Well Testing

Summary A new method is presented that uses transient well testing to determine the in-situ absolute permeability of the formation when three phases of fluids are flowing simultaneously in the reservoir. The method was verified through simulation using synthetic data, and its applicability and practicality were confirmed through application to field data. Determining the absolute permeability over the reservoir scale using readily available transient testing data will have major benefits in accelerating history matching and improving reservoir-performance prediction. A recently developed method (Kamal and Pan 2010) to determine the in-situ absolute permeability under conditions of two-phase flow extended the applicability of transient well testing and has been adopted in commercial software. In this study, We extend the analysis method to determine the absolute permeability and fluid saturations when three phases are flowing in the reservoir. We show that an optimization procedure is needed to obtain the required results in this case. We show that the theoretical bases for the method presented to determine absolute permeability from transient tests under multiphase-flow conditions are the same as those used in obtaining relative permeability relations from core analysis and predicting reservoir performance in reservoir-simulation studies. The method presented in this study uses surface flow rates and the fluid properties of the three phases. It also uses the same relative permeability relations used in the simulation models, thus ensuring that the same permeability values calculated from field data are used in history matching and predicting the performance of the reservoir. It is assumed that the fluid saturations are relatively uniform in the region around the well at the time of the transient test. The method was verified by comparing the input values with the results obtained from analyzing several synthetic tests that were produced by numerical simulation. Data from a deepwater field were also used to test the practicality and validity of the method. For the field case, the method was verified by matching reservoir production and pressure using the calculated absolute permeability. Excellent agreements were obtained for both synthetic and field cases.

Including and using internal multiples in closed-loop imaging — Field data examples

Nowadays, it is more widely accepted that multiple reflections should not be considered as noise, but as signal that can provide additional illumination of the subsurface. However, one of the challenges in seismic imaging is including all multiples in the migration process for field data in a reliable manner. Although including surface multiples in imaging has been demonstrated already on field data in recent years, the proper imaging of internal multiples is less established. We have determined successful field data applications on imaging that takes all internal multiples into account. This is done via so-called full-wavefield migration (FWM), an inversion-based method in which, given the migration velocity model, the angle-dependent reflectivity is iteratively estimated by minimizing the misfit between the modeled and the measured data. Its forward model is based on a multidimensional version of the so-called Bremmer series, which allows modeling of transmission effects and any type of multiple scattering in the subsurface and, thereby, is able to minimize the data misfit correctly. An application of FWM on deepwater field data from the Norwegian North Sea validates its capabilities to explain and image internal multiples. Furthermore, it is demonstrated on the same field data that the FWM framework can also be used for data interpolation and primary/multiple separation.

Comments: Offshore Makes a Comeback

Editor's column All eyes in the upstream continue to be on the growth in unconventional production, particularly in the US. But the offshore arena may be making a quiet comeback, at least in the near term. The US Gulf of Mexico, North Sea, Latin America, and other spots have seen renewed interest of late, as operators enforce capital discipline to make these expensive projects feasible given the current price climate. Many offshore megaprojects were cut or scaled back when oil prices began to drop sharply in 2014 and, while global offshore output has been steady, it has not grabbed the head-lines that surging shale production has. World offshore output has remained about 27 million B/D over the past decade. US Gulf of Mexico production, which is rising, made up a quarter of US output in the early 2000s but captures only 16% of the total now with the rise in unconventionals. US Gulf of Mexico production in 2017 rose to 1.65 million B/D, the highest annual level on record, according to the US Energy Information Administration (EIA). It is expected to increase this year and in 2019, maintaining record highs. Output will creep to 1.7 million B/D in 2018 and then to 1.8 million B/D in 2018, according to the EIA. This is due mainly to projects that were sanctioned before the price downturn and went forward in 2016 and 2017. The EIA says that seven deepwater fields will start production this year and another three will start up the following year. Shell will begin production from three fields over the period—Gotcha, Rydberg, and Kaikias. Hess and LLOG both will start up two fields, and Stone Energy and Apache will bring one field each online. An offshore auction by the US government in March, the largest for drilling prospects off the US Gulf Coast in history, attracted only modest interest from operators, proving that they are still wary of market conditions. The bidding was for 77 million acres of deep- and shallow-water tracts. Interest offshore Mexico and Brazil remains high. Brazil’s offshore auction in late March brought winning bids from ExxonMobil, Wintershall, Chevron, Shell, BP, Statoil, and Qatar Petroleum. Several operators said their break-even price for offshore projects is now under $50/bbl, well below where prices were trading in mid-April. The success of Brazil’s auction was not only because of rising oil prices and better capital discipline among operators, but also changes in Brazil regulatory laws that made the projects more attractive. That followed a deepwater auction in Mexico earlier this year that saw aggressive winning bids from Shell, which snatched up nine blocks, as well as Petronas and Qatar Petroleum. But offshore production will not catch US onshore output, which continues to outpace expectations despite fears of infrastructure bottlenecks and people shortages. Total US production will reach 11 million B/D this year, a whole year earlier than projected in March, the EIA said in April. Output is averaging 10.2 million B/D so far this year. The EIA expects US production to reach 11.18 million B/D next year.

A Comprehensive Wellbore Stability Model Considering Poroelastic and Thermal Effects for Inclined Wellbores in Deepwater Drilling

Exploring and developing oil and gas in deepwater field is an important trend of the oil and gas industry. Development of deepwater oil and gas fields from a platform always requires a number of directional wells or extended reach wells targeting to different depth of water in various azimuth. Drilling of these wells is mostly associated with a series of wellbore instability problems that are not encountered in onshore or shallow water drilling. In the past decades, a number of studies on wellbore stability have been conducted. However, few of the models are specific for wellbore stability of the inclined deepwater wellbores. In this work, a comprehensive wellbore stability model considering poroelastic and thermal effects for inclined wellbores in deepwater drilling is developed. The numerical method of the model is also presented. The study shows that for a strike-slip stress regime, the wellbore with a low inclination poses more risk of wellbore instability than the wellbore with a high inclination. It also shows that cooling the wellbore will stabilize the wellbore while excessive cooling could cause wellbore fracturing, and the poroelastic effect could narrow the safe mud weight window. The highest wellbore collapse pressure gradients at all of the analyzed directions are obtained when poroelastic effect is taken into account meanwhile the lowest wellbore fracture pressure gradients at all of the analyzed directions are obtained when both of poroelastic effect and thermal effect are taken into account. For safe drilling in deepwater, both of thermal and poroelastic effects are preferably considered to estimate wellbore stability. The model provides a practical tool to predict the stability of inclined wellbores in deepwater drilling.

Methodology for the Experimental Analysis of Offshore System in Deep and Ultra-Deep Waters in the Colombia Caribbean Sea

Historically, different methodologies of experimental analysis of naval and oceanic structures oriented to the execution of controlled experimental tests in facilities capable of reproducing environmental conditions specific to their operating locations have been developed. These methodologies enable the efficient design of oceanic structures, the minimization of production costs and the generation of scientific knowledge. This article details the design of an experimental analysis methodology for semi-submersible offshore systems for deep and ultra-deep water fields, obtaining satisfactory results, and the validity of the procedure as an important contribution to the phases of semi-submersible platform design, a concept selected as appropriate for the areas of interest of the Colombian Caribbean

Generalized Darboux transformation and parameter-dependent rogue wave solutions to a nonlinear Schrödinger system

In this work, we are concerned with a generalized nonlinear Schrodinger equation, which can describe the propagation of nonlinear wave phenomena in plasma, optics and in deep water field. We construct, up to the second-order expansion, rogue wave solutions and give general formula to obtain higher-order ones to this system. We investigate the effects of the higher-order nonlinearity on the rogue waves dynamics. We make use of the generalized Darboux transformation, based on the Darboux matrix method.

Advances in 4D Seismic and Geophysical Monitoring of Deepwater Fields

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27828, “Advances in 4D Seismic and Geophysical Monitoring of Deepwater Fields,” by Kanglin Wang, Paul Hatchell, David Chalenski, and Jorge Lopez, Shell, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission. Integrated surveillance is critical for understanding reservoir dynamics and improving field management. A key component of the surveillance is areal monitoring of subsurface changes by use of time-lapse geophysical surveys such as 4D seismic. The complete paper reviews the advances in these technologies with recent examples from the Gulf of Mexico (GOM) and deepwater Brazil. Data-Quality Improvement 4D seismic has played a pivotal role in monitoring offshore fields for some time. However, until recently, its application in the GOM had been limited, largely because the effects of the Loop Current and infrastructures make it difficult to repeat the feathering of streamers used in conventional 4D-seismic acquisition. The key for 4D success is to repeat everything in baseline and monitor surveys to make sure the time-lapse difference observed in the data reflects real subsurface changes rather than differences in data-acquisition conditions or processing work flows. To solve the challenge of streamer-positioning repeatability, an operator used ocean-bottom nodes (OBNs) to achieve highly repeated surveys at the Mars Field, and excellent 4D results were obtained. Since then, 4D seismic has been deployed successfully at the portfolio scale in the GOM and that operator’s 4D surveillance strategy has been changed from streamer seismic to ocean-bottom seismic (OBS), which includes OBNs and ocean-bottom cables. In addition to source and receiver positions, other conditions in data acquisition can play important roles in 4D repeatability—for example, the variation of water properties during a seismic survey and between different surveys including water depth (tides) and seismic velocity in water. Such variations have been a well-known issue that limits the repeatability of 4D seismic, in particular for OBS data where multiple migration is often used. Seismic travel-time analysis is traditionally used to estimate errors and make corrections, but the process is often complicated by coupled factors including tides, water velocities, positioning errors, and the clock drift of OBNs, which collectively make it difficult to achieve precise water static corrections. To address this challenge, a seafloor device called the Pressure Inverted Echo Sounder (PIES) was developed for direct measurement and continuous monitoring of water- column properties during marine seismic surveys. A PIES is deployed at the seafloor and monitors two-way water time by transmitting an acoustic signal and measuring the time it takes to be reflected back from the surface. Such information has been used to make travel-time corrections of seismic data for enhanced data repeatability in the operator’s 4D processing projects.

Pipeline walking and anchoring considerations in the presence of riser motion and inclined seabed

Steel Catenary Risers (SCRs), are increasingly becoming an attractive option for many deepwater field developments. SCRs are typically used to transport fluids between floating production vessels and pipelines. Typical uses may also involve the transport of produced fluids from a subsea production system to a floating production vessel or the transport of gas or water for re-injection into the producing reservoirs. The floating production vessel on which the steel catenary riser is supported will be subject to motions caused by environmental loads, and influenced by the mooring system and other risers. Horizontal movement of the vessel causes changes in the riser catenary configuration in near, mean, and far positions. On the seabed, the riser is connected to a pipeline that extends for some distance from the riser touchdown point, to its tie-in point on a pipeline or other facility. Effective tension at the touchdown point is necessary to maintain the riser configuration which may cause the pipeline to walk in the axial direction. The development of axial walking is in part due to the pull experienced on the pipeline at the touchdown point from the SCR tension. In this paper, the results of the effective axial force and the pipeline end expansion using a finite element study are presented to highlight the effect that the changing SCR tension, combined with the thermal transients and a global seabed slope along the pipeline length, has on the pipeline walking. Additionally, the paper provides some guidance in regards to the selection of the optimum location for the hold-back anchors, to ensure that pipeline walking does not compromise the integrity of both the SCR and the pipeline system.In general, the results show that SCR bottom tension provides the dominant walking mechanism and can exceed the other walking mechanisms associated with thermal transients and seabed slope. For a straight short pipeline, in the range of 2–3 km, where there is no lateral buckling, it is recommended to install the anchor towards the PLET (Pipeline End Termination) and away from the SCR transition point.

4D DAS VSP as a tool for frequent seismic monitoring in deep water

Thanks to its relatively low cost, time-lapse vertical seismic profiling (VSP) with distributed acoustic sensing (DAS) is an attractive proposition for frequent seismic monitoring around production and injection wells, aimed at production optimization in complex deepwater fields. We demonstrate that 4D DAS VSP provides sufficient data quality for reservoir monitoring in deep water, with a high value-to-investment ratio. 4D quality and image extent can be enhanced through well-executed acquisition and advanced processing. Further cost lowering via innovations on the source side is being pursued. The path to establishing 4D DAS VSP as a monitoring tool in deep water is through further field applications to demonstrate its ability to impact business decisions.

Vertical Correlation of the Acoustic Field in Deep Water Measured with Explosive Sources

In this paper we report the measurement and analysis on vertical correlations of acoustic signals received by a vertical line array deployed near the sea bottom in deep water. The source data were from one calibration experiment of sound exposure level of explosive charges. The source–receiver range is about 17 km. The sound transmission duct is the well-known reliable acoustic path (RAP). The vertical correlation coefficients are estimated at center frequencies of 300, 600, 1000 and 1500 Hz with 1/3 octave bands. Two types of explosive charges are used with nominal source depths of 50 and 300 m, respectively. The variation of vertical correlation coefficients strongly relies on source depth and center frequency. For each scene, ten groups of experiment data exhibit uniform variation of vertical correlation coefficients with fractional differences due to the fluctuation of ocean waveguide. Besides, the noise-free numerical modeling results reach good agreements with the measured ones, which reflect the stability of RAP as a sound transmission duct in the space/frequency domain. Due to the obvious arrival structures of rays, the theoretical solution of vertical correlation coefficient is derived based on the ray theory. At last, the effects of source–receiver geometry on the variability of vertical correlation are discussed.

Approach Redefines Ideal Project Scope and Facilities Size for Field Development

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 182269, “An Investigation of the Optimal Definition of Project Scope, Facilities Sizing, and Design Life for Truly Sustainable Deepwater Field Development: Technical Aspects and Economic Considerations,” by Francesco Beltrami, SPE, Energo Engineering, and Andrew Gifford, Shiladitya Basu, and Andre Berardi, Granherne, prepared for the 2016 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 25–27 October. The paper has not been peer reviewed. This paper investigates how decisions made through reservoir evaluation and drilling-and-completion planning affect the design of subsea production systems and, in turn, the design of production hosts. Practical alternatives are explored by challenging the current approach to project framing and definition. Rethinking the requirements of deepwater-field development will help define the proper size of the subsea and surface facilities, the optimal design life, and the possible need for staged developments. Introduction During the past 2 years, the offshore industry has looked with increasing interest, and undeniable concern, to practical and effective ways to reduce the capital expenditure (Capex) of deepwater projects. Looking at the three main components of a deepwater-field production infrastructure—host, subsea production system including export, and subsea wells—the host offers the greatest opportunity for Capex reduction. Cost reduction is achievable by optimizing the subsea production system and by adopting new technologies and practices for the construction of subsea wells, but a more relevant cost reduction is possible in principle by properly sizing the host. This, in turn, requires rethinking the way deepwater projects are sanctioned and contracts between local governments and operators are negotiated. The fact that over capacity exists in offshore hosts is well-documented. Less evident, but still convincing, is the fact that several subsea tiebacks, successfully con ducted over the past decades across the world, were possible only because a host already existed nearby that had available process or storage capacity. Sometimes, overdesigning a host may not be avoidable because of the limited time the operator has to develop and produce the offshore fields. If contracts were structured in a different way and the operators had the chance to operate the offshore field for a longer period, it might have been possible to use smaller hosts and subsea production systems, thus reducing both Capex and operational expenditure (Opex). Project Framing and Host Sizing Overview. Before a deepwater project starts its life cycle, and then periodically during the cycle, reservoir engineers and drilling-and-completion engineers study and determine the optimal way hydrocarbons can be recovered. Subsequently, wells and completions are designed to achieve this goal. The decisions made within these disciplines become part of the basis-of-design document that is the starting point for other disciplines tasked with the design of the host and the subsea production system.

Event-based risk management for subsurface risks: An approach to protect value generation from oil and gas fields

ABSTRACT Event-based risk management (EBRM) is an improved way of describing subsurface uncertainties and their possible business impacts in a manner that facilitates specific actions to improve business performance. In EBRM, uncertainties are viewed as potential causes of risk events that could in turn lead to consequences that affect the attainment of objectives. This “causes–event–consequences” syntax aids the design of prevention measures to inhibit the causes turning into the event and mitigation measures to reduce the potential consequences should the risk event occur, and it also facilitates construction of a risk taxonomy scheme based on risk consequences, events, and causes. Using a data set of 1456 subsurface risks, each risk was described in this manner and placed in the taxonomy, and the proportion of risks in each taxonomic group was analyzed. This revealed clear trends in the relative frequency of risk groups with type of field: for example, risks related to hydrocarbon-in-place volumes are more frequently identified in deep-water oil fields and gas fields feeding liquefied natural gas plants, situations in which resource volumes are critical to support the large project capital costs. Trends were also evident with field maturity: for example, risks related to hydrocarbon-in-place volumes are more frequently identified before the field sanction decision than afterward. Several benefits have yielded from EBRM: the risk description syntax encourages the creation of meaningful risk-management actions, the taxonomy and associated risk identification frequencies assist the identification of relevant risks so that key risk areas are not overlooked and also help to anticipate future risks, and the focus on risks (rather than uncertainties) helps to focus resources (data acquisition, technical studies) onto those aspects of the subsurface that are likely to impact business outcomes.

Monitoring and Mitigating Asphaltene Issues in a Deepwater Production System

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27123, “Strategies To Monitor and Mitigate Asphaltene Issues in the Production System of a Gulf of Mexico Deepwater Subsea Development,” by Doris Gonzalez, Fabio Gonzalez, Marney Pietrobon, Mehdi Haghshenas, Megan Shurn, Amber Mees, Carlos Stewart, SPE, and Chinenye Ogugbue, SPE, BP, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission. An asphaltene threat was identified in production wells located in a Gulf of Mexico deepwater field. During reservoir-fluids characterization, asphaltenes were identified as a key risk factor for successful field development. This paper presents an integrated approach to evaluate the key elements of asphaltene risk for deepwater projects, the strategy to manage the issues during production implementation, and aspects to be considered in the mitigation of asphaltene in the field-development plan. Introduction Asphaltene precipitation and deposition can occur at different stages during petroleum production, causing reservoir formation damage and plugging of pipelines and production equipment. Remediation of asphaltene deposits requires solvent-soaking operations, followed by removal through exposure to turbulent flow. These intensive operations require high amounts of chemical solvents with potential effects on health, safety, and environment, along with production deferrals because of operations downtime. The focus of this study is to understand the effects of asphaltene precipitation in a Gulf of Mexico deepwater field. The approach is based on reservoir-fluid characterization and monitoring tools. Being able to predict the presence and type of trouble zones along the production system from downhole to production facilities is becoming progressively more important as water depths increase. Acquisition of Downhole Fluid Samples High-quality pressurized bottomhole samples were collected for asphaltene-onset-pressure (AOP) and wax-appearance-temperature (WAT) measurements in pressure-compensated chambers. Because the samples tend to cool to below reservoir temperatures as they are retrieved from the well, the samples were maintained at pressures above reservoir condition at all times to reduce the possibility of irreversible asphaltene precipitation resulting in non-representative samples. Asphaltene Prescreening The de Boer Plot. The de Boer plot is a method to screen crude oils for their tendency to precipitate asphaltenes. It essentially evaluates the loss of asphaltene solubility as a reservoir-fluid sample is depressurized. This pressure/volume/temperature screen is a crossplot of in-situ density and the degree of undersaturation with respect to gas (the difference between reservoir pressure and saturation pressure). Because this screening assumes that the fluid is saturated with respect to asphaltene at reservoir conditions, it is extremely conservative.

A systematic approach to pipe-in-pipe installation analysis

In the present study, the selection of a pipe-in-pipe (PIP) system which includes an installation analysis modelling technique is investigated. The PIP system has become the standard pipeline design for subsea field developments, especially for deep water fields. One of the most important design challenges for engineers is the pipeline installation design. A design underestimation of loads could result in serious damage, while overestimation would result in high operation costs. An accurate or improved modelling method is definitely required for the PIP system. The modelling of a finite element single pipe-lay simulation has been studied and discussed by many authors, and is very much understood by the people in the industry. However, modelling complex PIP systems for pipe laying simulations in order to obtain accurate results is quite challenging. To build the most economic finite element (FE) model for the pipe-lay simulation of PIP systems, various modelling aspects of the installation have been studied separately. In this work, three types of FE models which are two models with different simplifications and one actual PIP model were established and compared. Finally, a systematic approach selection for performing a PIP installation is presented.

Benchmark of deepwater field development projects in the Perdido foldbelt: Evaluating fiscal impacts (Mexico, and US) using a nodal analysis production model

Development of Mexican hydrocarbon reservoirs by foreign operators is now made possible by the energy reforms implemented in 2015. This study benchmarks the economic return of deepwater hydrocarbon field development projects located in the Perdido foldbelt at either side of the maritime border between the United States and Mexico to assess the competitiveness of the respective fiscal frameworks. We use a nodal analysis production model to first history match real field performance in the US Perdido project and then forecast production of an analogous, undeveloped field in the Mexican extension of the Perdido foldbelt, Gulf of Mexico. The new Mexican profit sharing contract imposes basic royalties that appear equitable for both the contractor and the government, albeit slightly less attractive than the to the U.S. federal lease terms. The contracts for deepwater assets in Mexico open up commercially viable options, provided the oil price will recover to render such oil projects profitable. Our sensitivity analysis shows that profitable development of 300 MMbbls oil in place becomes possible when oil prices rise above $75/bbl. For larger reservoirs (~900 MMbbls) the profit hurdle rate of 15% is already met for $60/bbl. Any over-royalty offered by a contractor in the bidding process renders the royalties in Mexican operations slightly higher than in the U.S.

Technology Focus: Deepwater Projects

Technology Focus The oil-price downturn has dominated the news cycle during the past 18 months and is expected to dictate the fate of many deepwater developments. In addition, the prices have challenged the economic viability of many future deepwater projects, resulting in cancellations and deferred sanctioning. Optimism about a possible recovery of oil prices has picked up recently in the offshore energy industry, but I believe that 2017 and 2018 are going to be complicated and that this optimism may be premature. Despite near-term concerns, the long-term fundamentals for deepwater activity remain strong. The need to offset declining production from mature basins, as well as the ability of international oil companies to access larger reserves with the use of new exploration-and-production technology, will continue to drive deepwater expenditure. Deepwater exploration-and-production activities are driven by a variety of supply- and demand-side factors: The need to offset declining production from onshore and shallow-water basins The potential discovery of large hydrocarbon reserves, with East Africa a clear example Economic viability of deepwater developments Despite the prolonged low oil prices, there are some fast-track development plans for large deepwater fields such as Eni’s Zohr gas discovery in the Mediterranean offshore Egypt and ExxonMobil’s Liza discovery off Guyana, which are capital-intensive but provide large potential returns on investment. In line with this growing trend, Royal Dutch Shell has categorized deep water as one of its growth priorities for the next 5 years. From now until 2020, growth in the deepwater market is expected to be constrained as low oil prices increase pressure on project economics. Operators, subsea manufacturers, and rig owners are likely to find the next few years to be difficult as project delays continue through the forecast period. However, decreasing drilling and equipment costs may provide a limited upside for sanctioning. Recommended additional reading at OnePetro: www.onepetro.org. OTC 27161 Floater and SURF Combined and Optimized Solutions by Blaise Seguin, Subsea 7, et al. OTC 27260 Progress in the Development of Test Methods and Flexible Composite Risers for 3000-m Water Depths by T.A. Anderson, GE, et al. SPE 179056 Deepwater Riserless Operations With Coiled Tubing in the Gulf of Mexico: An Innovative, Safe, and Efficient Plug-and-Abandonment Technique by Renny Ottolina, Coil Tubing Services, et al.

Surface wave predictions in weakly nonlinear directional seas

We have employed laboratory and numerical experiments in order to investigate propagation of waves in both long and short-crested wave fields in deep water. For long-crested waves with steepness, ϵ=kcac=0.1 (a fairly extreme case), reliable prediction can be performed with the modified nonlinear Schrödinger equation up to about 40 characteristic wavelengths. For short-crested waves the accuracy of prediction is strongly reduced with increasing directional spread.

Case History: High-Pressure/High-Temperature Underbalanced Drillstem Testing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 178089, “Case History: HP/HT Underbalanced Drillstem Testing, Deepwater KG Offshore,” by Mahesh Sarode and Milind Khati, Halliburton, prepared for the 2015 SPE Oil and Gas India Conference and Exhibition, Mumbai, 24–26 November. The paper has not been peer reviewed. This paper describes the method developed to achieve underbalanced drillstem testing (DST) in a deepwater field offshore India. DST tools rated to 450°F and 15,000-psi differential pressure were configured to maintain integrity and successfully evaluate the well potential. By use of a multicycle DST tool string, the reservoir potential was tested safely and effectively with an underbalanced test fluid in two deepwater wells, achieving the desired test objectives. Introduction An operator in India needed to conduct high-pressure/high-temperature (HP/HT) drillstem testing on a deep-water well with low-density clear brine in the annulus. Performing DST was necessary to assess hydrocarbon potential in the deep water block for further field- development plans. The DST tools performed satisfactorily for approximately 18 days during the test on a semi-submersible rig. The well was completed in a 6-in. hole, which resulted in a 5-in. casing program, thereby creating a significant challenge. The retrievable packer suitable for the 7-in. casing was set above the 5-in.-liner-hanger top, resulting in a tail pipe of approximately 350 m. Well killing at the end of the DST with such a long tail pipe was a challenge. The method of operating DST tools in both underbalanced brine and kill-weight mud was developed along with a meticulously designed well-test program and a well-kill procedure with a long tail pipe below the 7-in. retrievable packer. Before lowering the DST tools, a well- integrity test was performed by conducting an inflow test for a 5-in.-liner shoe, a 5-in.-liner-hanger top, and a 7-in.-liner-hanger top. Hermetic tests were per-formed to ensure that casings sustained the required annulus pressure for operation of the DST tools.