Deepwater Gulf Of Mexico Research Articles

Insight of in-situ porosity and compressibility of the GC 955 Gulf of Mexico hydrate reservoir

We characterize the in-situ porosity and compressibility of a coarse-grained hydrate reservoir in Green Canyon Block 955 in the deepwater Gulf of Mexico by performing experiments both on a hydrate-bearing sandy silt pressure core and on the same reservoir material after reconstituting. Uniaxial consolidation experiments demonstrate a small difference in porosity between a reconstituted sandy silt sample (Sh= 0,n= ~ 0.38) and a hydrate-bearing sandy silt (Sh= 83%,n= 0.39-0.40) at in-situ effective stress (3.8 MPa). Both measured porosities generally agree with the in-situ porosity (~0.38 to 0.39) of the reservoir formation that was best-estimated from both LWD and calibrated PCATS densities. The compression index of pressure core at 3.8 MPa is ~ 0.05 to 0.1, slightly stiffer than reconstituted sandy silts (Cc= 0.11). This difference in porosity and compression behaviors between hydrate pressure cores and reconstituted material implies that (1) analysis of reconstituted sediments from hydrate-bearing pressure cores provides a simple and intuitive approach to understand some petrophysical components of the hydrate reservoir; and (2) the high-saturation hydrate in the pores of sediments makes the hydrate reservoir slightly less compressible, suggesting a non-contact-cementing hydrate morphology in the pressure core.

Introduction to Special Issue: Gas Hydrates in Green Canyon Block 955, deep-water Gulf of Mexico: Part I

Introduction to Special Issue: Gas Hydrates in Green Canyon Block 955, deep-water Gulf of Mexico: Part I

A practical workflow using quantitative interpretation of seismic amplitudes to derisk infill wells in deepwater Gulf of Mexico: The Auger example

Seismic direct hydrocarbon indicators (DHIs) are routinely used in the identification of hydrocarbon reservoirs and in the positioning of drilling targets. Understanding seismic amplitude reliability and character, including amplitude variation with offset (AVO), is key to correct interpretation of the DHI and to enable confident assessment of the commercial viability of the reservoir targets. In many cases, our interpretation is impeded by limited availability of data that are often less than perfect. Here, we present a seismic quantitative interpretation (QI) workflow that made the best out of imperfect data and managed to successfully derisk a multiwell drilling campaign in the Auger and Andros basins in the deepwater Gulf of Mexico. Data challenges included azimuthal illumination effects caused by the presence of the Auger salt dome, sand thickness below tuning, and long-term production effects that are hard to quantify without dedicated time-lapse seismic. In addition, seismic vintages with varying acquisition geometries led to different QI predictions that further complicated the interpretation story. Given these challenges, we implemented an amplitude derisking workflow that combined ray-based illumination assessments and prestack data observations to guide selection of the optimal seismic data set(s) for QI analysis. This was followed by forward modeling to quantify the fluid saturation and sand thickness effects on seismic amplitude. Combined with structural geology analysis of the well targets, this workflow succeeded in significantly reducing the risk of the proposed opportunities. The work also highlighted potential pitfalls in AVO interpretation, including AVO inversion for the characterization of reservoirs near salt, while providing a workflow for prestack amplitude quality control prior to inversion. The workflow is adaptable to specific target conditions and can be executed in a time-efficient manner. It has been applied to multiple infill well opportunities, but for simplicity reasons here, we demonstrate the application on a single well target.

Managed-Pressure Cementing Provides Zonal Isolation in Deepwater Gulf of Mexico

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194536, “Managed Pressure Cementing (MPC) Within a Narrow Pressure Window, Deepwater Gulf of Mexico Application,” by Michael Teoh, Sharief Moghazy, SPE, Keith Smelker, and Roger Van Noort, SPE, Shell, and Juan C. Valecillos, Julian Hernandez, and Maurizio Arnone, Weatherford, prepared for the 2019 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Amsterdam, 9–10 April. The paper has not been peer reviewed. Managed-pressure cementing (MPC) is an important technique for primary cementing operations in wells with narrow pressure margins between the pore and fracture gradients. This paper presents the design considerations, methodology, and results of two deepwater MPC operations conducted to cement production casing strings within a target operating window of approximately three-tenths of a pound.•Modern transient hydraulic modeling software permits the calculation of adequate surface pressure levels to control the annular pressure profile during the different stages of a cementing operation. On the basis of a•predetermined annular pressure target, different variables can•be designed to produce surface and•downhole pressures within existing limits of a particular operation. This capability, combined with modern managed-pressure-drilling (MPD) systems, enables accurate control of the annular pressure profile during cementing and makes it possible to obtain near-constant bottomhole pressure (BHP) throughout the cement•placement operation while using statically underbalanced mud columns. Introduction Preventing fluid losses during slurry placement generally is necessary in achieving the goals of a cementing operation. Effective zonal isolation behind the casing or liner wall is related intimately to preventing losses toward, and flow from, the formation during and after the cement circulation. When cementing a casing or liner string within limited openhole pressure margins, maintaining the bottomhole circulating pressure below the fracture gradient is not feasible in most cases when using conventional methods. Cementing fluid dynamics are generally more complex than the fluid dynamics observed during the drilling phase. Additionally, multiple fluids with diverse properties and with generally higher viscosities are pumped at different rates. All of these factors, combined with high cement-slurry densities, contribute to equivalent circulating density (ECD) levels at the well bottom during cementing that are not observed while drilling. In many cases, these ECD levels lead to losses or even fracturing of the formation. The inability to measure downhole pressures during the operation adds to the complexity of the cementing job. In recent years, MPD systems, with their ability to control precisely the well pressure profile, have emerged as an alternative solution to the problem of cementing efficiently within tight margins in deepwater wells. Used together with advanced hydraulic modeling software that can predict fluid properties accurately downhole under dynamic and static conditions, the latest MPD systems are enabling drilling engineers to manipulate variables that in the past were out of reach during the drilling and cementing-job planning. The two wells discussed in the complete paper were drilled in the Gulf of Mexico (GOM) in approximately 8,500 ft of water from rig kelly bushing to mudline. The paper provides definitions related to the MPC subject, an overview of the applications, a summary of the engineering approach and calculations, and the results obtained during these cementing operations.

Technology Focus: Offshore Drilling and Completion (October 2019)

Technology Focus Measured-pressure approaches (drilling, cementing, and completions) have offered much promise for some time but have been slow to reach widespread application. A spate of technical developments, deployments, trials, and applications, however, recently has pushed measured-pressure drilling (MPD) and its nuanced variants to their full potential as viable well-construction methods. Development of fully integrated drilling, control, and management systems, along with surveillance and data-processing enhancements, have brought the idea of fully functional real-time measured-pressure management to reality. Increasing experience, design feed-back, validation, and enhancements are making a number of derivatives of the approach widely applicable. As well as the drilling operations themselves, experience has increased to include all aspects of the well-construction process, including both cementing and completion running operations. Increasing equipment automation and surveillance and control systems is now providing confidence and accuracy with well-calibrated models of in-situ behavior. Additionally, the real-time management of operations creates a feedback loop that allows continuous improvement to be at the heart of execution and learning. As broader industry experience and case history volume increases, the ability to deploy and use these approaches will provide additional flexibility to operators as they develop increasingly challenging formations and tight or complex pore-pressure fracture-gradient profiles and windows. Measured-pressure techniques and variants now appear to be coming of age, and wider application will continue to enhance and enrich their functionality. Continued automation, data management, and personnel training and experience will support the continued and increasing deployment of these approaches. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 194538 The Business Case for Use of Applied-Backpressure Managed-Pressure Drilling in Deepwater Gulf of Mexico by Sharief Moghazy, Shell, et al. SPE/IADC 194541 Acoustic Telemetry Network Provides Real-Time Downhole Data Transmission During Drilling, Cementing, and Completion Installation for Use in Depleted Reservoirs and During Managed-Pressure Operations by Andy Hawthorn, Baker Hughes, a GE company, et al. SPE/IADC 194554 Using Managed-Pressure Drilling and Early Kick/Loss Detection System To Execute a Challenging Deepwater Completions Job in the Gulf of Mexico by Julian Hernandez, Weatherford, et al.

Integrating Fractional Flow Into Reservoir Surveillance Improves GOM Production

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 192843, “A Success Story of Production Improvement in a Deepwater GOM Field Based on Integration of Surveillance Techniques,” by Fabio Gonzalez, SPE, Doris Gonzalez, Steve Carmichael, SPE, Carlos Stewart, SPE, Marney Pietrobon, and Francisco Garzon, SPE, BP America, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed. Integration of well and reservoir surveillance techniques—production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow—are critical to understanding well and reservoir performance for effective well and field management, particularly in high-cost intervention environments. The complete paper presents a case study in the deepwater Gulf of Mexico (GOM) in which pressure transient analysis (PTA), fractional flow (FF), and production logging tools (PLT) were integrated to identify correctly the cause of, and execute an effective remedy for, a•well’s productivity deterioration. Background The level of integration achieved in this study is not common practice because most commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values. In this case, integrating fractional flow analysis with a multilayer PTA curve and running a production-logging tool made it possible to separate relative-permeability effects from plugging effects. A coiled-tubing (CT) mud acid-stimulation treatment then enabled recovery of approximately 65% of the well’s lost transmissibility, decreased formation skin from 16 to 9, and instantaneously restored 7,000 STB/D of production. This analysis approach has been recommended to determine the potential production-optimization benefits of future intervention candidates. The complete paper discusses the geology and reservoir characterization of the well, its initial performance and subsequent deterioration, the surveillance tools used to evaluate the well’s performance and determine the intervention method and steps, a comparison between basic diagnostic PTA and multilayer PTA, the building of the multilayer model, the execution of the stimulation treatment, and the results and conclusions of the program. Field Case A subsea deepwater GOM well began production in 2009 with an initial rate of 35,000 STB/D with no water production and a gas/oil ratio (GOR) of 1100 scf/STB. The well was equipped with a downhole pressure gauge (DHPG) that worked for only 90 days, during which it was possible to adequately establish a baseline well performance and accurate determination of formation damage (skin) and transmissibility. In July 2013, the well was shut in because of a stuck-closed subsurface safety valve (SSV). The well was back on line in 2014 after replacement of the upper completion, which included a new SSV and DHPG. Fig. 1 shows aspects of the well history.

Shear strength variability analysis for design of on-bottom pipelines in deep water Gulf of Mexico

A large portion of the uncertainty involved in the design of high-pressure-high- temperature oil and gas pipelines installed subsea is associated with the variability in the shear strength of soil supporting the pipeline. This study investigates variability of shear strength in the top half-meter of the seabed at three deep water sites in the Gulf of Mexico. Nearly 400 undrained shear strength data from minivane tests conducted on soft clay from 38 box core samples are evaluated for the presence of spatial correlation (autocorrelation) structure. Findings show a high degree of scatter and a lack of spatial correlation in both undisturbed and remolded shear strengths. Classical linear regression modelling, which is applicable in the absence of autocorrelation, is used to determine (i) the mean strength, (ii) 95% confidence intervals for the mean strength and (iii) 95% prediction intervals for a single new observation for different depths. The linear regression approach implemented may be used to identify characteristic strength profiles corresponding to different levels of confidence. This approach produces strength profiles suitable for use in typical pipe-soil interaction analysis and is easily implemented. Although not new, to the author’s best knowledge, it hasn’t been used for seabed soils for pipeline design.

The Importance of Clean Off-Plane Perforations in all Phases of a Deepwater Well and its Productivity Impact

Summary High–permeability reservoirs in deepwater Gulf of Mexico (GOM) have been completed with frac packs, resulting in high–production–rate wells. The initial production rates for these wells range from 3,000 B/D to almost 40,000 B/D; and these rates can be sustained over extended periods of time (several years). Most of these developments in the GOM require sand control with cased hole frac packs (CHFPs) as the preferred completion technique. In addition to providing reliable sand control, frac packs result in relatively low skin by bypassing near–wellbore damage. During the past few years, operators have focused on reducing skin and improving the production from these wells, leading to a more detailed analysis of frac–pack performance. This paper will demonstrate that in high–permeability reservoirs, production from the off–plane perforations is as important as production from the fracture. It examines the theoretical basis of the contribution of off–plane perforations to total flow and demonstrates the adverse effect on this contribution because of damage from drilling fluids and solids, cementing spacers and solids, fluid–loss materials, perforating debris, wellbore debris, and crosslinked gel. Three case histories are analyzed to evaluate and quantify these effects and to show that the lower the conductivity contrast between the (high permeability) reservoir and the fracture, the higher the production benefit that can be realized by effectively cleaning the off–plane perforations.

Technology Focus: Deepwater Fields (May 2019)

Technology Focus Deepwater capital expenditure has nose-dived since the oil-price crash of 2014 and has not quite recovered because of the high level of breakeven prices required, but some oil companies maintained their interest in the sector and went ahead with big-ticket projects anyway. Most believe the sector has bottomed out. Brazil’s presalt region is among the areas driving deepwater oil and gas development, while others struggle with costs and technical complexity. So, in a low-oil-price environment, are such deepwater projects viable? The major players in the deepwater market have made significant efforts to minimize costs and increase efficiency, thus shaping 2019 capital budgets. That means activity levels in 2019 likely will mimic those of 2017–18, with perhaps some small gains from small operators taking advantages and looking for opportunities in the current low-cost environment. However, the situation is darkened by global market pessimism. Adding to this, operator project-execution decisions have been delayed and lack of commitment and direction has caused operators to delay deepwater projects and leave the pipeline of future work empty. Even if operators do make decisions in late 2019 to go forward with these projects, the projects are unlikely to commence until late 2020 or even 2021. Royal Dutch Shell is considering only the Gulf of Mexico in their strategic deepwater development going forward to 2020 and beyond, and, despite low oil prices, Shell is advancing its Kaikias, Appomattox, and Coulomb Phase 2 projects in the deepwater Gulf of Mexico, reducing break-even costs and cycle times. Through the forecast period, Africa and the Americas will continue to lead the deepwater market, accounting for 79% of forecast expenditure. Floating production, storage, and offloading vessels will continue to dominate the floating production and storage (FPS) market, with a total of 33 deepwater units (out of 41 FPS units in total) expected to be installed during the 2018–22 period, representing 78% of FPS expenditure. Recommended additional reading at OnePetro: www.onepetro.org. OTC 28872 Changing Landscape of Deepwater-Field Developments by Marcel M. Landwehr, Subsea 7, et al. OTC 29043 The Giant Lula Field: World’s Largest Oil Production in Ultradeep Water Under a Fast-Track Development by Marcelo Becher Rosa, Petrobras, et al. SPE 191960 Early-Stage Detection of Scales in a Deepwater Field Offshore Ghana Through Remote Monitoring of Multiphase Meter by Mahdi Darab, OneSubsea, et al.

BP Gulf of Mexico Neogene Astronomically-tuned Time Scale (BP GNATTS)

AbstractThis paper introduces an integrated Neogene microfossil biostratigraphic chart developed within post-merger BP for the Gulf of Mexico Basin and is the first published industrial framework “fully-tuned” to orbital periodicities. Astronomical-tuning was accomplished through a 15-year research program on the Ocean Drilling Program’s (ODP) Leg 154 sediments (offshore NE Brazil) with sampling resolution for calcareous nannofossils and planktonic foraminifera ∼20 k.y. and 40 k.y. (thousand year), respectively. This framework extends from the Late Oligocene (25.05 Ma) to Recent at an average Chart Horizon resolution for the Neogene of 144 k.y., approximately double that of published Gulf of Mexico biostratigraphic charts and a fivefold increase over the highest resolution global calcareous microfossil biozonation. Such resolution approximates that of fourth to fifth order parasequences and is a critical component in the verification of seismic correlations between mini-basins in the deep-water Gulf of Mexico. Its utility in global time-scale construction and correlation has been proven, in part, by application of the scheme in full to internal research for the Oligocene–Miocene boundary interval on the global boundary stratotype section and point (GSSP) in northern Italy and offshore wells in the eastern Mediterranean Sea. This step change in Neogene resolution, now at the level of cyclostratigraphy (the orbital periodicity of eccentricity) and the magnetostratigraphic chron, demonstrates the potential for calcareous microfossil biostratigraphy to more consistently reinforce correlations of these time scale parameters. The integration of microfossil disciplines, consistent taxonomies, and rigorous analytical methodologies are all critical to obtaining and reproducing this new level of biostratigraphic resolution.

Pattern Recognition Applied to Attenuation of Multiples in Subsalt Imaging

It is well known that high impedance contrasts between salt bodies and their surroundings yield blurriness in seismic images which does not allow adequate interpretation; some of the artifacts generated by this process are multiple reflections and diffractions. In this work we propose a novel method of detection and attenuation of multiples from seismic gathers which is based on pattern recognition and fuzzy logic. In order to corroborate the effectiveness of this new approach, we use synthetic models which mimic a region intensely affected by salt tectonics in deep-water Gulf of Mexico. We obtained synthetic seismic sections by simulating wave propagation with an FDTD–CPML formulation. Detection of seismic events is performed through the mapping of parabolic shapes in shot gathers that approximate the recorded wavefronts. Undesired multiple events are then surgically attenuated by using fuzzy threshold criteria. Results show an optimal attenuation of multiple events, even when they are not directly related to salt structures.

Technology Focus: Drilling Innovation (February 2019)

Technology Focus From the beginning, the name of the game has been innovation. No single word has characterized drilling design and operations more completely during the 160 years since Colonel Drake first probed the Pennsylvania landscape for oil. This fundamental aspect of our business applies now more than ever across geographical and corporate boundaries. Examples of evolution in well construction during the past several years include new horizontal-well applications, breakthroughs in bit and directional-drilling technology, synthetic fluids, fracture-stimulation advancements, managed-pressure drilling, and the digital revolution. All this being said, few could have imagined the present state of the industry unfolding with the development of unconventional resources. During the past 7 years alone, US oil production has again become a dominant global force, doubling from 5.5 million to more than 11 million B/D. Even greater effects on gas reserves have been realized with the expansion of infrastructure to deliver a rising tide of new gas production to consumers. Around the globe, the ultimate benefits of these current trends remain to be seen as new reserves continue to be identified within most of the world’s oil- and gas-producing regions. Papers selected for this feature serve as superb examples of drilling evolution in a variety of locations, including US onshore, offshore Thailand, deepwater Gulf of Mexico, Sakhalin Island, and the North Sea. In each case, evolution in well design, equipment, and operational procedures has occurred, resulting in dramatic advancements in technical feasibility, efficiency, and safety. Paper SPE 191783, “Drilling Extended Laterals in the Marcellus Shale,” reveals advancements underpinning new unconventional production in that area as well as in the Permian Basin, the Bakken, the Eagle Ford, and the Utica fields. Successful results published by international and offshore operators in Papers SPE 191054 and OTC 29065 highlight not simply new tools or procedures but also far-reaching breakthroughs that fundamentally alter the outlook and value of these types of assets. Papers referenced in the pages that follow offer but a glimpse into a greater library and wealth of knowledge available to SPE readers desiring to remain connected with drilling innovations. Recommended additional reading at OnePetro: www.onepetro.org. SPE 191090 Simultaneously Drilling and Underreaming Directional Topholes With Underreamer Below Mud Motor Saves a Trip in Collision-Free Operations: Offshore Sakhalin Island Case Study by Ruslan Kasumov, Schlumberger, et al. IADC/SPE 191099 Complete Managed-Pressure-Drilling Rigs: Is This the Future? by Ben Gedge, PVD Well Service, et al. SPE 191331 Drilling a Challenging Kvitebjørn Field 53/4-in. Section in a Single Run Using a New Mud-Motor-Modeling Engineering Work Flow and New Long-Life Elastomer by Hany Ahmed Beeh, Schlumberger, et al. SPE 191338 Out-of-Zone Injection by A. Galiev, PJSC Tatneft, et al.

Comments: A Year of Uncertainty

Editor's column Late December/early January is the time of year when industry outlooks are announced, revealing company spending plans, oil price predictions, and potential stumbling blocks. The steep drop in prices in the fourth quarter of 2018 made these outlooks particularly challenging, and most are laced with cautious optimism about the year ahead. But common themes emerge: the industry is still in cost-containment recovery mode; the march toward digitalization is in full swing; and shale output from the US will only increase as pipeline bottlenecks began to ease with new construction. This past year was one of recovery, as the downturn that began with the price crash in 2014 appeared to be over, although that view is not unanimous. Capital expenditures rose last year because of higher oil prices but spending was cautious, and that caution was validated when both Brent and WTI prices fell about $30/bbl during the fourth quarter. A price rally in January began to ease concerns that the industry was in another free fall. Oil and gas spending growth rose 4% in 2017 and 5% in 2018, according to the International Energy Agency (IEA), after dropping 60% during 2014–16. The US shale sector contributed largely to that growth, as spending on unconventionals outstripped interest in conventional oil and offshore. Majors increased their visibility in unconventionals in plays such as the Permian Basin. Shale remains a bright spot, and will allow the US to likely remain the world’s largest producer of liquids and gas. Global oil inventories have come down significantly since the downturn, even with the increase in US production. But major uncertainties exist, making this year “even more hazardous than usual” to forecast trends in 2019, an IEA spokesman was quoted as saying. That uncertainty is reflected in a recent survey of more than 30 oil analysts, who predicted that Brent prices would end the year anywhere from $30/bbl to $78/bbl. Deloitte’s 2019 industry outlook states that “opportunities from digital technologies are becoming increasingly apparent and have the potential to unlock new value.” As featured in JPT over the past year in particular, more companies are employing or experimenting with artificial intelligence, automation, machine learning, robotics, and blockchain, often attracting nontraditional vendors and startups. The offshore sector has yet to recover. US Gulf of Mexico (GOM) production rose last year but drilling activity did not, and the rig count ended the year at an 81% utilization rate. There were 36 active deepwater GOM sites at the end of the year, compared with 49 in early 2017, according to the US Bureau of Safety and Environmental Enforcement. Norway’s upstream regulator is not optimistic about spending there. Oil and gas production will fall 4.7% this year to 1.42 million B/D after a 6% drop last year, according to an annual report by the Norwegian Petroleum Directorate. Mexico’s offshore may be a bright spot, but the industry is still looking for signals from the new government that it is friendly toward private sector E&P.

Submarine Landslides Induce Massive Waves in Subsea Brine Pools

Subsea hypersaline anoxic brine pools are among the most extreme habitable environments on Earth that offer clues to life on other planets. Brine is toxic to macrofauna as remotely operated vehicles commonly observe dead and preserved remains in brine pools. While brine pools are often assumed to be stable stratified systems, we show that underwater landslides can cause significant disturbances. Moreover, landslides create large-amplitude waves upon impact with the brine pool, similar to tsunami waves. We focus on the Orca Basin brine pool in the deepwater Gulf of Mexico, which contains numerous landslide deposits and blocks that originated from scarps several hundred meters above the brine pool. The impact of massive fast-moving landslides generated waves with amplitude on the order of 100 s of meters, which rival the largest known ocean waves. Brine waves can negatively affect biological communities and potentially overspill to spread hypersaline brine into surrounding basins.

Technology Focus: Production and Facilities (December 2018)

Technology Focus Creativity and innovation have long characterized production and facilities, and this year is no exception. Much of the work reported this past year was conducted during the recent period of low oil prices. The economic challenges of the oil industry clearly have provided a strong stimulus for even more creativity and innovation. The use of big data and analytics appeared in a number of papers with an emphasis on the use of artificial intelligence (AI) for building databases used to monitor the health of equipment and structure risk-based-inspection (RBI) strategies. Monitoring data inputs from thousands of sensors (paper OTC 28990) allows an AI application to predict an impending failure and notify operators by text or email when the incipient problem is detected so that proactive maintenance can be scheduled to avoid an unplanned shutdown or catastrophic failure. This strategy is being successfully applied to compressors but no doubt will be used to monitor other high-cost, critical service equipment as well (paper SPE 188803). Progress continues on the design and application of inflow-control devices (ICDs). Introduced only a few years ago, these devices are still in a rapid development stage for both design and application. Now, ICDs are applied successfully to improve the fluid-injection patterns for both steamfloods and waterfloods, the latter being described as a successful field application (paper SPE 189824). For steamfloods, passive and autonomous ICD designs were evaluated and their performance modeled using computational fluid dynamics (paper SPE 189721). The integration of subsurface modeling and surface-facility design by the development of a data-driven stochastic work flow (paper SPE 187462) demonstrated a means to reduce both subsurface and facility costs by reducing the biases that inevitably come into play during the generation of a field-development plan. Other innovative work was reported on field optimization, the prediction of asphaltene precipitation, and the integration of RBI with vibration-induced fatigue failure of installed piping systems. Interesting work not discussed here includes evaluating corrosion under severe conditions and the development of an oil-droplet-coalescing pump for use in water treatment. Recommended additional reading at OnePetro: www.onepetro.org. SPE 188803 Machines Performance Algorithmic Modeling for Anticipating Machines Health Using Real-Time Condition-Monitoring Data by W. Almadhoun, ADMA-OPCO, et al. SPE 189721 Evaluation of Inflow-Control-Device Performance Using Computational Fluid Dynamics by M. Miersma, University of Alberta, et al. SPE 187256 Production Optimization of Shenzi Field in the Deepwater Gulf of Mexico by P. Ashton, BHP, et al. SPE 190149 A Diagnostic Approach To Predict Asphaltene Deposition in Reservoir and Wellbore by Davud Davudov, University of Oklahoma, et al. OTC 28352 Integrating an RBI Approach for Vibration-Induced Fatigue Into a Mechanical-Integrity Program by Paul Crowther, Wood, et al.

Interpretation of formation permeability and pressure responses from wireline formation testing with consideration of interlayers

We have developed a workflow to interpret formation permeability in a hydrocarbon reservoir with consideration of interlayers by numerically simulating the measured pump-out flow and pressure responses from wireline formation testing (WFT). With the field data obtained from a dual packer tool in the deepwater Gulf of Mexico, we have developed and validated a high-resolution numerical model to simulate the fluid-sampling process together with transient pressure. History matching has been performed with field data to assess the effective thickness and then interpret the permeability for each flow unit. In addition to generating eight cases under various configurations of laminated layers, we use pressure buildup derivatives obtained from packers and observation probes as a diagnosis tool to examine the effect of the interlayer on WFT measurements. Oil-based mud-filtrate invasion affects the early-time behavior of pressure transients because of the associated changes in fluid viscosity and compositions. Low vertical permeability can behave as a vertical barrier for the flow in a WFT tool, indicating the difference contrast in permeability between individual flow units. As for the field case, effective water horizontal permeabilities for tests 1 and 2 are 14.0 and 10.6 mD, respectively. Low vertical permeability results in a distortion in the derivatives, particularly during the transition between flow regimes. In a laminated reservoir, a radial flow regime will develop when the radial length of interlayer is greater than the vertical formation interval and when the complete circular shape of interlayer is formed. It is recommended that any observation probe be positioned in or below the interlayer to accurately define the vertical communication of interlayers and its configuration. If dual packers and observation probes are located in the same zone, their pressure responses exhibit the same flow regimes; otherwise, different pressure responses can be developed in the observation probes when a partially sealing interlayer exists.

Evaluation of Software-Based Early Leak-Warning System in Gulf of Mexico Subsea Flowlines

SummaryEarly detection of subsea pipeline leaks is a very serious and ongoing issue for the oil and gas industry with limited successful cases reported. For example, aerial surveillance of pipelines can be applied only for relatively shallow and concentrated areas, and an advanced technology such as fiber-optic cable can be considered at the significant expense of time and cost for installation and equipment. The objective of this study is to evaluate a software-based leak-detection technique through complex multiphase flow mechanics. More specifically, this study investigates (i) how leak-detection problems can be formulated from a fluid-mechanics viewpoint and (ii) how reliable such a technique can be under conditions resembling the deepwater Gulf of Mexico (GOM). In examining a wide range of scenarios, this study proves that software-based techniques have a potential for playing a key role in the future.First, this study defines a base case selected from the literature review of deepwater GOM flowlines in terms of pressure and temperature conditions, fluid properties, reservoir properties, and flowline characteristics that allows a steady-state flow in pipeline to be determined with no leak present. Next, leaks with certain opening sizes (dleak) at different longitudinal locations (xD = x/L) are positioned, and new steady states in the presence of leaks are calculated. By comparing the two steady-state responses (with and without leak), finally, the changes in two leak-detection indicators [i.e., change in upstream pressure (ΔPin) and change in downstream total flow rate (Δqt out)] can be calculated in a wide range of input parameters. This study presents the results in the form of contour plots for pressure and flow responses.The major finding of this study is that, theoretically, it is possible to estimate both size and longitudinal location of the leak with the two leak-detection indicators in the software-based leak-detection method. The results from various subsea flowline conditions [such as different gas/oil ratios (GORs) and fluid types, water depths, pressures at the receiving facilities, inclination angles, pipe diameters, water cuts, and so on] show that the reliability of this technique is improved when the sink term (i.e., amount of leaking fluid) is more dominant, which, in turn, means that leaks positioned farther upstream, with larger opening size, and occurring at higher pressure inside pipe are relatively easier to detect. In many of the scenarios considered, Δqt out as a leak-detection indicator shows more than a 10% change in the presence of a leak with dleak>1 in., allowing relatively easier activation of a leak-warning system, which demonstrates the robustness of this technique. Other scenarios in which the indicators are less than a few percent changes, however, may be challenging—in those cases, additional responses from other methods (hardware-based or transient simulation) will be helpful.

On the Use of Distributed Temperature Sensing and Distributed Acoustic Sensing for the Application of Gas Lift Surveillance

Summary Fiber-optic (FO) -based sensing technologies such as distributed temperature sensing (DTS) or distributed acoustic sensing (DAS) for well surveillance are attractive because they offer a continuous collection of real-time downhole data without the need for well intervention, thus avoiding production deferment. An example is the application of DTS and DAS for gas lift performance monitoring in oil producers by measuring the thermal and acoustic effects from the flow of lift gas through the valves into the production tubing to determine the active, inactive, and possibly leaking valves, and, also, the unloading depth. An anomaly observed in DTS data of a deepwater Gulf of Mexico (GOM) gas lifted oil producer led to a significantly improved interpretation methodology that allows inferring both the lifting depths and the annular-fluid interface(s). These results were confirmed by DAS, by identifying gas flow through a valve in selected acoustic-frequency bands. The new insights have been applied to five wells in the GOM and Southeast Asia.

Integrating statistical rock physics and pressure and thermal history modeling to map reservoir lithofacies in the deepwater Gulf of Mexico

We have developed an approach integrating statistical rock physics with pressure and thermal history modeling for quantitative seismic interpretation (QSI). Extending the training data for lithofacies classification and deriving distributions for scenarios not available in the original training require knowledge about geologic processes affecting the elastic properties in the subsurface. We model pressure and thermal history and corresponding smectite to illite diagenesis with a basin model across Thunder Horse minibasin in the Gulf of Mexico. By comparing the mapped lithofacies with and without basin-modeling extrapolations against the results of a reference workflow, we found the value of integrating basin modeling results and statistical rock physics with QSI workflows. The reference workflow uses all available data from two wells in the QSI. The first workflow performs the same lithofacies classification with data from only a single well and does not account for spatial trends away from the well. In the second workflow, we use data from only a single well, the same well as in the first workflow, and bring in extrapolation from the basin and petroleum system modeling at the location of the second well. Results for the first workflow indicate significant differences with the reference workflow in the training data, the quality of the inverted impedance volumes, and the classified reservoir lithofacies. In the second workflow, the guided extrapolation of the training data accounts for spatial trends away from the well and the quality of the impedance inversion significantly improves. The predicted lithofacies map in this scenario shows only minor differences from the reference workflow, and the posterior probabilities of lithofacies show less uncertainty compared with the first workflow. The superiority of the second workflow demonstrates the added value of the integration workflow to QSI in cases of spatially limited well control.

US Gulf of Mexico Production Projected To Hit Record High

The deepwater US Gulf of Mexico (GOM) sector has struggled since the onset of the oil price downturn in 2014, but as costs settle and operators establish new standards for running efficient projects, this year may be a significant turning point for the industry in the region. In January, Wood Mackenzie published a report predicting that production of oil and gas in the deepwater GOM will reach an all-time record high this year, with more than 1.9 million BOPD, surpassing the previous record set in 2009 by nearly 10% and representing 13% growth year over year. William Turner, Wood Mackenzie’s senior research analyst and lead author of the report, Deepwater GoM: 5 Things to Look for in 2018, said that, more than 2 months into the calendar year, the level of activity in the region is still on track to meet expectations. However, recent developments may have an effect on that trajectory. Policy Impacts In January, the US Department of the Interior (DOI) announced a proposal to place more than 90% of federal offshore land containing oil and gas—including land in the GOM—up for auction between 2019 and 2024. In February the DOI’s Royalty Policy Committee issued a recommendation for lower royalty rates for offshore oil and gas drilling on sea-bed owned by the US government. If approved, royalties from off-shore drilling would drop from 18.75% to 12.5%, the lowest royalty rate per-mitted. The US Bureau of Ocean Energy Management (BOEM) had already relaxed royalty rates to 12.5% for some shallow-water leases in August 2017. With the WTI and Brent crude prices still hovering in the low $60s as of early March amidst relatively high supply, the recommendation could make it more attractive for operators to look at bidding for offshore oil leases in the GOM. Turner said while the decision on the royalty came faster than anticipated, it is likely the US federal government wanted it in place before Lease Sale 250 on 21 March. At the time of this writing, it was scheduled to be the largest regionwide sale in US history, with 77.3 million acres offshore Texas, Louisiana, Mississippi, Alabama, and Florida avail-able for exploration and development. The sale includes approximately 14,700 unleased blocks located in the GOM’s Western, Central, and Eastern planning areas. The BOEM estimated that these blocks contain about 90 billion bbl of undiscovered technically recoverable oil and 327 Tcf of undiscovered technically recoverable gas. The royalty rate may have a bigger impact on operators’ decision making in the coming months. For instance, Turner said it is possible that Total may try to rebid for leases in the North Platte field—where it holds a 40% working interest—rather than taking over operation of its holdings from Cobalt International Energy.