Offshore Abu Dhabi Research Articles

Drilling Dynamics, Mechanical Specific Energy Data Help Drill Record Extended-Reach Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203335, “Using MSE and Downhole Drilling Dynamics in Achieving a Record Extended-Reach Well Offshore Abu Dhabi,” by Nashat Abbas and Jamal Al Nokhatha, ADNOC, and Luis Salgado, Halliburton, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Complex extended-reach-drilling (ERD) wells often present challenges with regard to geological aspects of data requirement and transmittal, reactive geosteering response times, and accuracy of well placement. Such scenarios may require innovative approaches in Middle East carbonate reservoirs. The objective of the complete paper is to illustrate that, by assessing the details of reservoir geology and key operational markers relevant for best practices, drilling approaches can be customized for each reservoir or scenario. Reservoir Background and Geology The planned reservoir section is a single horizontal of approximately 25,000-ft lateral length at a spacing of 250 m from adjacent injectors. The well was drilled from an artificial island. Field A, a shallow-water oil field, is the second-largest offshore field and the fourth-largest field in the world. Horizontal drilling was introduced in 1989, and an extensive drilling campaign has been implemented since then using steerable drilling technologies. This study is concerned only with wells drilled to develop Reservoir B in Field A, which contributes to the main part of initial oil in place and production. The thick limestone reservoir is subdivided into six porous layers, labeled from shallow to deep as A, B, C, D, E, and F. Each porous layer is separated by thin, low-porosity stylolites. The reservoir sublayer B, consisting of approximately 18-ft-thick calcareous limestones, was selected as the target zone for the 25,420-ft horizontal section. ERD, constructed on artificial islands, began on 2014 with a measured depth (MD)/true vertical depth (TVD) ratio approaching 2.2:1 or 2.4:1. A recent ERD well, Well A, was drilled at the beginning of 2020 with a MD/TVD ratio of 5:1. This value is a clear indication of progressively increasing challenges since the start of the project. Mechanical specific energy (MSE) has long been used to evaluate and enhance the rate of penetration (ROP); however, its use as an optimization tool in ERD wells has not been equally significant. This may have been mostly because of historical use of surface-measured parameters, which do not necessarily indicate the energy required to destroy the rock, particularly in ERD wells. Using optimization tools as part of the bottomhole assembly (BHA) downhole close to the bit provides actual weight-on-bit (WOB) and torque-on-bit (TOB) applied to the drilling bit to destroy the rock and, thus, results in more-representative MSE measurements to optimize drilling parameters and ROP in ERD wells.

Technology Focus: Extended-Reach and Complex Wells (May 2021)

In selecting papers for this feature, reviewer Stéphane Menand of Helmerich and Payne has identified a trio of papers that investigates new approaches toward familiar issues encountered when drilling complex well types. Whether considering the customization of drilling approaches in Middle Eastern carbonate reservoirs, implementing a collaborative work flow in tackling high-tortuosity wells offshore Western Australia, or researching the ability of a fibrous material to effect hole cleaning as opposed to polymeric sweeps, the authors of these papers understand that technical expertise may not be completely realized if it is not applied to problems in original ways. In carbonate reservoirs, the goal of drilling extended-reach wells is set against the geological makeup of such formations, the complexity of which adds significant uncertainty to geosteering and well placement. The authors of paper SPE 203335 develop a work flow that makes possible the customization of drilling scenarios through an emphasis on mechanical specific energy, as well as the use of an optimized borehole-assembly design. The work flow helped deliver what the authors write is the longest well in the Middle East offshore Abu Dhabi. In a similar vein, the authors of paper SPE 202251 describe a challenging scenario involving an ultraextended-reach well in a mature field offshore Western Australia. The project overcame shallow water depth and a high tortuosity requirement by implementing an integrated plan that used a reservoir-mapping-while-drilling service. The authors stress that this technology, coupled with active collaboration between specialists, town, and rig site, allowed the project to achieve the desired oil-column thickness with zero collision incidents. Highly deviated wells often face problems resulting from ineffective hole cleaning. Paper SPE 203147 studies the properties of a fibrous material when compared with the hole-cleaning performance of common polymeric pills. The authors write that the fibrous material proved effective, in part because of a unique characteristic in which a spiderweb-like network of fibers is created that does not allow cuttings to settle easily in complex wells. In addition, the material is environmentally friendly. All three papers approach well- established problems in the critical industry sector of extended-reach drilling with innovation and confidence. Enjoy the papers and be sure to search SPE’s OnePetro online library for more fresh approaches to the technical challenges posed by these well types. Recommended additional reading at OnePetro: www.onepetro.org. SPE 196410 - Analysis of Friction-Reduction System During Drilling Operation at a High-Inclination Well on Field X by Rizqiana Mudhoffar, Tanri Abeng University, et al. SPE 197257 - Successful Management of Collision Risk in an Extended-Reach Well by Manchukarn Naknaka, Mubadala Petroleum, et al. SPE 202730 - Challenges in Drilling and Completion of Extended-Reach-Drilling Wells With Landing Point Departure of More Than 10,000 ft in Light/Slim Casing Design by Nitheesh Kumar Unnikrishnan, Abu Dhabi National Oil Company, et al.

Walkaway VSP in ultra-shallow water images deep Paleozoic targets, offshore UAE

In 2019, ADNOC decided to record walkabove and walkaway VSP surveys in a deep deviated well, in ultra-shallow waters offshore Abu Dhabi. The field is part of a major gas and condensate development project in UAE. The primary objectives included vertical travel times and velocities, robust well to seismic tie, and higher-resolution VSP images of the Palaeozoic-age targets. Other objectives included acoustic impedance inversion and anisotropy calibration. This was the first time a walkaway was acquired with only 2 m of water depth and in a deep hostile downhole environment. This study showed the importance of pre-survey modelling to achieve the VSP objectives. The data were acquired in continuous mode with GPS time stamping. Good data quality was recorded, despite high temperature, deep targets, multiple casings and a small volume seismic source deployed at 1 m depth. Wideband 5–90 Hz data were retrieved across 6 km of complex overburden, resulting in images with three-fold resolution improvement compared to the surface seismic data. The VSP also provided acoustic impedance sections of the deeper targets and measurements to optimize surface seismic processing. The results validate the viability of 3DVSP surveys with similar shallow-water source and downhole receiver array for reservoir characterization and well placement.

Extensive Well-Testing Operations Provide Insight Into Khuff Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203441, “Lessons Learned From Extensive Well-Testing Operations in Khuff Formations Offshore Abu Dhabi,” by Florian Hollaender, SPE, Schlumberger, and Mahmoud Basioni and Ahmed Yahya Al Blooshi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. An extensive appraisal campaign was performed in the Khuff reservoirs offshore Abu Dhabi, with multiple appraisal wells drilled in different fields. Those wells were evaluated using detailed logging campaigns and then subjected to well tests, usually through drillstem testing for targeted intervals. The interpretation of well tests, combined with advanced petrophysical analysis, formation-test data, and production logs, provided insight into the nature of the Khuff reservoirs. A wide range of responses was observed, from tight to highly productive, but not necessarily with clear previous indications of deliverability or inflow intervals. Overview of the Khuff Formations The key characteristics of the Khuff formations offshore Abu Dhabi have been well-documented in previous work and can be summarized by the following: Low porosity and permeability carbonate reservoirs, where natural fractures are critical contributors to flow Properties vary widely laterally, with significant uncertainty regarding connectivity Variations in stress and petrophysical properties can be significant and affected by diagenetic and tectonic history These reservoirs present significant challenges for development planning. Previous studies have shown that it can be difficult to relate production performance to standard petrophysical analysis directly and that the presence of fractures - in particular, critically stressed fractures - in the vicinity of the wellbore is an essential factor for production performance. Productivity also was found to vary by several orders of magnitude within the same reservoir depending on the field and lateral location of a given well. The presence of natural fractures has been recognized as a major contributor to flow in tight gas reservoirs; however, this raises several questions related to assessing formation potential. First, the nature of the fractures must be evaluated. Some will contribute to production, while others will remain sealed. Equally importantly, identifying zones with promising porosity developments is not a solid indicator of production expectations. Well-Test Observations With more than 20 drillstem tests performed in the Khuff reservoirs during a 4-year period, the first observation is the wide range of reservoir responses encountered, with an apparent lack of consistency within a given reservoir or field.

Cased-Hole Standalone Evaluation Succeeds in the Absence of Openhole Data

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 202894, “Cased Hole Standalone Evaluation: Breaking the Barrier To Successfully Evaluate Challenging Deep Carbonate Reservoirs,” by Pradeep Menon and Carey Mills, ADNOC, and Suvodip Dasgupta, SPE, Schlumberger, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. Accurate petrophysical evaluations (formation lithology, porosity, and water saturation) are essential in characterizing potential reservoir zones and estimating resources in place. Typically, these evaluations rely on acquisition of openhole logging measurements; however, this is not always possible. The complete paper outlines two examples from tight gas reservoirs in two separate fields offshore Abu Dhabi in which openhole data could not be acquired and petrophysical analysis was undertaken using cased-hole log data. These evaluations successfully identified gas-saturated porous intervals in each well, one of which was successfully flow-tested. Introduction A growing need exists to increase gas production in the UAE. As a result, specific gas-production targets have been mandated from development of currently undeveloped deep gas carbonate reservoirs such as the Permo-Triassic Khuff formation, the middle Jurassic Araej formation, and the Permian Pre-Khuff Unayzah and Berwarth formations. Recent appraisal wells have aimed at evaluating these reservoirs systematically by acquiring a good suite of openhole logs, cutting conventional cores, and conducting well-testing operations. These well data are combined with an evolving regional understanding to better assess and ultimately develop these complex formations. An accurate petrophysical evaluation requires the petrophysicist to develop a realistic evaluation of formation lithology, porosity, and water saturation. These parameters provide the foundations for further work such as static modeling stands, and they must be robust. The Upper Khuff is composed of dolomite occasionally grading to calcareous dolomite with minor interbeds of claystone and anhydrite. In core and cuttings, the dolomite in the uppermost section exhibits a grainstone texture with poor intercrystalline/intergranular porosity. The Lower Khuff is composed of very hard dolomite in part grading to calcareous dolomite, medium-to-dark grey-brown in places, with occasional very-fine-to-medium grainstone texture and very poor intercrystalline porosity. In this paper, the Upper and Lower Araej members are interpreted to have been deposited in an open, marine- circulation shelfal environment, while the Uweinat member is considered to have been deposited in a more- restricted circulation setting with-in a similar shelfal environment. The Barrier Openhole logging generally is the preference for formation evaluation because it represents the simplest environments and benefits from a comprehensive list of available measurements. The variety of tools and diversity of output data available make openhole log acquisition the gold standard for formation evaluation. However, in certain situations in which openhole logging is not possible because of borehole conditions (re-entry of old cased wells, wellbore instability, over-pressure), no option exists other than acquiring petrophysical data in a cased-hole environment.

Infill drilling and well placement assessment for a multi-layered heterogeneous reservoir

This paper presents an assessment of infill drilling opportunities in a complex multi-layered heterogeneous carbonate formation located in Abu Dhabi offshore. The subject field was developed last century and is currently undergoing further development with line drive horizontal wells. The field is being redeveloped for improved oil recovery at higher production rates with long horizontal wells. An infill assessment process is defined using sector model reservoir simulations for the specific reservoir. Reservoir simulations are performed on pattern sector models to establish the optimum grid for infill evaluation. Also, the models with an appropriate grid size are used to optimize infill placement (vertical and lateral well placement) and infill drilling timing for a couple of geologically similar areas. In the second step, the sector model results are applied to test the full-field infill development plan. The relatively homogeneous geological area shows very uniform displacement with 1-km spaced wells and gives no considerable benefit of incremental recovery through infill drilling. However, in a comparatively heterogeneous geological area, considerable incremental oil recovery is quantified. In brief, this paper presents a detailed infill drilling and well placement assessment process workflow for the re-development of a multi-layered heterogeneous reservoir.

Mechanical characterization of Laffan and Nahr Umr anisotropic shales

Geomechanics-related wellbore instability has become a major source of non-productive time in highly deviated wells drilled in oil and gas fields in offshore Abu Dhabi. These wells are drilled through two highly anisotropic shale formations, namely the Laffan shale formation and the Nahr Umr shale formation. Most of the models used in the oil and gas industry do not account for the strength and elastic anisotropy of shale. Therefore, a laboratory study was conducted to examine the strength and elastic anisotropy of shales using uniaxial compression tests and triaxial compression tests.Jaeger's Plane of Weakness (JPW) model was used to understand the anisotropic failure behavior of highly laminated shales of the Laffan and Nahr Umr formations. This model assumes that for an anisotropic rock, there exists a plane of weakness that has strength properties (cohesion and angle of internal friction) different than the strength properties of the intact rock. By minimizing the Root Mean Square Error (RMSE), the experimental strength values of the samples, as measured at different orientations, were fitted to the JPW model.Elastic moduli were also measured on these shales, as a function of orientation angle. The results showed that the moduli vary with angle according to the expected tensor transformation law. Therefore, the transverse isotropy assumption is a reasonable model to be used when dealing with these laminated sedimentary rocks.

Determining Infracambrian Hormuz Salt and Basement Structures Offshore Abu Dhabi by Joint Analysis of Gravity and Magnetic Anomalies

SummaryHydrocarbon fields that are located offshore Abu Dhabi, United Arab Emirates (UAE), are known to be associated with undulating thick sedimentary sequences. These undulations are mostly influenced by variations in the depth of Infracambrian Hormuz salts that generate negative gravity anomalies. Nonetheless, a few known oil fields are uncorrelated with the airborne gravity observations. This is attributed to the interference from large positive gravity anomalies from basement highs. To filter out the effect of basement, we calculate the pseudogravity effect of the airborne magnetic anomalies and subtract it from the gravity anomalies. The resultant gravity anomalies mainly represent the effect of the salt domes. The results uncover deep salt structures and introduce potential traps for hydrocarbons that have proved difficult to map accurately with current seismic techniques. A nonlinear 3D inversion modeling of corrected magnetic and decreased gravity data is also used to determine the depth to basement and the Infracambrian Hormuz salts over two regions. Our findings demonstrate that the depth to basement in these regions changes from 7100 to 9700 m, and the depth to Infracambrian Hormuz salt changes from 5800 to 9400 m, with a variable thickness with a maximum of 2700 m.

Contribution of Tidal Analysis to Reservoir Monitoring: A Field Case Study in a Fractured Reservoir Offshore Abu Dhabi, UAE

Summary Offshore reservoirs are subjected to pressure loading from the ocean tide. The resulting pressure fluctuation, notably its amplitude and phase, provides valuable information regarding the formation compressibility and heterogeneity. The purpose of the present study is twofold: First, to propose a method for calculating tidal efficiency from harmonic analysis of regional tide stations and detrended bottomhole pressure (BHP), and second, to compare the compressibility from tidal analysis with that obtained from rock-mechanics measurements and material balance. This case study is on a fractured oil field for which matrix laboratory measurements alone cannot capture the large-scale formation compressibility that is driven by the fracture distribution. This paper will show how, in the absence of seabed-pressure measurements, a synthetic diurnal tide can be simulated by interpolating the harmonic constituents of neighboring tide stations. The validity of this method was confirmed on two offshore fields. A new procedure that combines a Savitzky and Golay (1964) (SG) filter and cubic splines gave satisfactory results to filter out the tidal signal residual from the reservoir-transient response for both buildup and interference tests. In addition, this paper found that wells in fractured areas of the field have higher rock compressibility and exhibit a higher tidal efficiency. The same effect is observed in flank wells with higher water saturation. Conversely, the tidal efficiency is dramatically reduced in wells experiencing gas breakthrough.

Morphology of the basement and Hormuz salt distribution in offshore Abu Dhabi from constrained 3-D inversion of gravity and magnetic data

Many seismic surveys and exploration wells have been conducted in offshore Abu Dhabi, United Arab Emirates. However, the Neoproterozoic basement and the Infracambrian Hormuz salts were not imaged or penetrated by seismic and well data. To delineate the morphology of the basement and distribution of salt bodies, we applied a 3-D constrained inversion method to aerogravity and aeromagnetic data covering offshore Abu Dhabi. Well and seismic data were used to constrain and validate the inversion results. The magnetic inversion model resulted in a robust basement model that varies in depth from 8 to 10 km with two highs at 8 and 8.5 km highlighting possibly magmatic bodies. In contrast, the gravity inversion model does not delineate very well the basement morphology, possibly due to the lower density salt bodies masking the gravity response of the higher density basement. By calculating and removing the gravity response of the magnetic basement model from the observed gravity data, we recovered the residual gravity response of the Hormuz salts. The 3-D gravity inversion of the residual shows that the Hormuz salts are more wide-spread and thicker than previously thought with a depth to top of salt varying from 5.5 to 8.5 km. This salt model suggests that the giant oilfields in offshore Abu Dhabi, such as Umm Shaif, Nasr, Abu Al-Bukhoosh, Zakum, Sarb and Hail, occur exactly above crests of salt pillows. In addition, a series of smaller oilfields are found located at the margin of the northern basement high, and three structural lineament trends (NE-SW, NW-SE, and N-S) were identified from the inverted basement and salt models. Reactivation of these fault trends and associated diapiric salt uplifts, as observed in the seismic sections and curvature map, played a major role in shaping the basement morphology and mobilization of the Hormuz salts.

Fractures extraction and associated intensity maps from 3D VSP data

Fractures and faults were extracted from a reverse time migrated 3D Vertical Seismic Profile (VSP) data acquired over a carbonate reservoir offshore Abu Dhabi in the United Arab Emirates. A specifi...

Nonaqueous, Nondamaging Fluid Implemented Offshore Abu Dhabi

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 192735, “The Evolution of Nondamaging Fluid Design and Implementation Offshore Abu Dhabi,” by Catalin Ivan, SPE, ExxonMobil; Yousif Saleh Al Katheeri, Melanie Reichle, Khalid Akyabi, James Thomas Ryan, Sheldon Peter Anthony Seales, SPE, and Sigit Kustanto, SPE, ADNOC; Laurie Hayden, M-I SWACO; and Christoper Steele, SPE, ELKEM, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, 12–15 November, Abu Dhabi. The paper has not been peer reviewed. This paper covers the 7-year history of drilling-fluids application in a reservoir drilling campaign offshore Abu Dhabi, from the early use of a solids-free, brine-/water-based mud to the recent application of nondamaging, nonaqueous fluids (NAFs) with micronized acid-soluble ilmenite. The complete paper provides details about the integration of filter-cake breakers with various types of drilling fluids, from dormant drilling-fluid additives to delayed, pH- and temperature-activated breakers. The paper describes the steps taken to achieve these performance goals, including changes to the oil/water ratio (OWR), internal phase composition [heavier calcium briomide (CaBr2) instead of calcium chloride (CaCl2)], and a micronized, acid-soluble ilmenite as a•weighting agent. Development Highlights A key objective for the offshore Abu Dhabi project was to drill longer horizontal 8½-in. intervals while retaining zero-skin completions. This necessitated reducing the torque and drag and coefficients of friction (COF). Achieving these design criteria required developing a nondamaging, nonaqueous (NAF) drilling fluid complemented with a filter-cake-removal breaker system. Emphasis was placed on the design of an NAF that combined the desired properties of low rheological profile for equivalent-circulating-density (ECD) management, low COF, and nondamaging water-based-mud (WBM) formulation. Four different generations of breakers for water-based reservoir drill-in fluids (RDF) were developed and used before moving to nondamaging NAF. The NAF went through three iterations in addition to fine-tuning of the breaker package. Data related to well information, reservoir rock type, and completion type were gathered and analyzed. Fluid interaction and other studies were performed to determine suitable fluid type and formulation. Other factors taken into consideration included offset well data, drilling requirements, environmental considerations, logging requirements, and likely mud-damaging mechanisms. Extensive laboratory tests were conducted, some of which included compatibility of various fluids, return permeability, changes to the OWR, internal phase composition, and a micronized, acid-soluble ilmenite as a weighting agent. The breaker systems saw the same extent of refinement, from enzymes to delayed organic acid precursors and chelating agents, to evaluate the removal of the fluid filter cake by the breaker. Fluid formulations were evaluated and optimized. More than 80 extended-reach-drilling wells have been drilled using both water-based and nonaqueous RDFs, each with specially formulated breakers. These wells yielded learnings that contributed to the current design and formulations. Friction factors (FFs) obtained using RDF NAF proved to be much lower than those with RDF WBM. The lower FF enabled wells with longer horizontal sections to be drilled successfully and at significantly higher rates of penetration. Using micronized, acid-soluble ilmenite lowered ECD as compared with sized calcium carbonate. Additionally, the evolution of breaker formulations allowed for longer breakthrough time, which allowed for better coverage of the lateral, better removal of the filter cake, and, ultimately, enhanced production through improved inflow profiles. The end result of the continuous improvement in reservoir drilling fluid was an NAF that combined the desired properties of low rheological profile for ECD management and low COF, and was•nondamaging.

Integrated sedimentological and seismic reservoir characterization studies as inputs into a Lower Cretaceous reservoir geomodel, offshore Abu Dhabi

Abstract Reservoir characterization plays a fundamental part in the development and/or appraisal of any hydrocarbon field. Understanding and quantifying the characteristics and distribution of the reservoir rock properties is an evaluation step that needs to be performed before starting any reservoir model. An accurate description of the reservoir is vital to help appropriately manage and optimize oil recovery. From core to seismic scale, any relevant piece of information should be integrated in order to reduce uncertainties, and optimize understanding of the final flow behaviour and fluid distribution inside the reservoir. The goal of the final geomodel is to obtain consistent properties that are driven by the geological facies models (including depositional facies and diagenesis; reservoir rock types) and trended by the seismic information.

Data-Driven Analytics Provide Novel Approach to Performance Diagnosis

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192759, “Data-Driven Analytics: A Novel Approach to Performance Diagnosis Using Spatiotemporal Analysis in a Giant Field Offshore Abu Dhabi,” by Mohamed Mehdi El Faidouzi, SPE, and Djamel Eddine Ouzzane, ADNOC, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed. This work describes a heuristic approach combining mathematical modeling and associated data-driven work flows for estimating reservoir-pressure surfaces through space and time using measured data. This procedure has been implemented successfully in a giant offshore field with a complex history of active pressure management with water and gas. This practical work flow generates present-day pressure maps that can be used directly in reservoir management by locating poorly supported areas and planning for mitigation activities. Field Overview The giant oil field offshore Abu Dhabi covers an area of approximately 40×25•km. The structure is a low-relief anticline. The fault pattern is dominated by steep northwest/southeast strikes, with less-abundant northeast/southwest strikes. The fault throws are generally small, and most faults are unlikely to be sealing laterally. The oil accumulation is separated by dense argillaceous limestones into three distinct, stacked reservoirs (A, B, and C), each approximately 20 to 35 ft thick. Formation-pressure tests showed good intrareservoir vertical pressure communication. Occasionally, especially toward the north and east, a generally tight clay-prone lithology forms a localized barrier between the upper and basal layers of Reservoirs A and B. The complete paper examines the case of the upper layers of Reservoir A in particular, a laterally extensive porous carbonate deposited in a shallow-water environment, although the work flows developed are equally applicable to other reservoir zones. Commercial production of Reservoir A began in the late 1960s. After an initial period of natural depletion, various pressure-maintenance strategies were deployed, namely dump-flood (1972–1984), peripheral water injection (from 1979), and crestal gas injection (from 2005). Spatiotemporal Analysis of Pressure Data Prediction of spatial random fields is a common task in geostatistics and arises in geology, mining, hydrology, and atmospheric sciences. Kriging procedures are used routinely to make optimal predictions at unsampled locations. For quantities that vary in space and time, such as reservoir pressure, spatiotemporal interpolation can provide more-accurate predictions than purely spatial interpolation because observations at other times are considered. In producing oil and gas assets, reservoir-pressure measurements are made at a much higher frequency in the time domain compared with the spatial domain, which requires additional wells to be drilled. The conventional approach of using a spatial interpolation on the basis of a certain time period misses valuable information and could result in inconsistencies between maps from one time period to the next. In this case study, the authors present a heuristic approach to estimating reservoir pressure maps in Reservoir A on the basis of spatiotemporal interpolation. Reservoir pressure is modeled using smooth functions that capture global trends while preserving the spatial and temporal continuity of pressure and pressure gradient. The residuals can be described by a stationary and spatially isotropic process. Residuals then can be predicted at unsampled space and time locations by kriging.

Extraction and characterization of faults and fractures from 3D VSP data in a carbonate reservoir: A workflow

We present a workflow for the extraction and characterization of fractures and faults using a Reverse Time Migrated (RTM) volume from 3D Vertical Seismic Profile data (3D VSP) acquired in an oilfield offshore Abu Dhabi in the United Arab Emirates. The workflow consists of: preconditioning of the input RTM volume, which involves removal of acquisition footprints; extraction of faults and fractures using a semblance based discontinuity attribute; binary filtering and clustering for characterization and interpretation using prior geological information, as well as removals of unwanted features such as those related to stratigraphy; and finally interpretation. Complex networks of lineaments were extracted after application of the workflow. The location of lineaments with length greater than 200 m and orientated WNW-ESE to NW-SE correlates with a known flower structure which has a trend similar to that of the Proterozoic Najd Fault System that cut the Arabian Peninsula. Lineaments with strike directions ENE-WSW and NE-SW are interpreted to be related to reactivation of basement faults and correspond to the Hormuz Salt basin's major trend in the Arabian Gulf. Dominant strike directions of lineaments at three reservoir levels correlate with dominant strike directions of interpreted fractures from Fullbore Formation Microimager (FMI) and core data; thus implying that they are likely related to fractures or fracture corridors. Lineaments with orientation NNE-SSW correlate with closed fractures while lineaments with orientation NNW-SSE correlate with open fractures. Zones with relatively high fracture intensity are generally located north and north-west of the VSP well in the reservoir zones. The good correlation of the results with interpreted fractures from core and FMI data shows the robustness of the workflow and gives confidence to the results.

Technology Focus: Coiled Tubing (June 2019)

Technology Focus During the past several years, lean philosophies, methods, and techniques have been applied steadily and increasingly within the upstream segment of the oil and gas industry. Perhaps one of the more notable areas for this growth has been in unconventional well completions and field development with references to such endeavors as the “well factory.” In part, this has been focused on optimizing well and pad construction to establish a uniformity of processes and equipment. This allows a greater focus on elimination of the various forms of waste, as defined in lean concepts, to drive various efficiency gains. However, applying these concepts to well interventions proves challenging. The coiled-tubing (CT) industry, like other well-intervention segments, has applied lean philosophies to some aspects of its management, operations, processes, and equipment. When it comes to CT application to specific in-well operations, no two wells are the same. Even though the operations may be nominally similar, well variables such as temperature, pressure, depth, and fluids can make it difficult to understand the cause and effect. The continued high activity level in the unconventional and shale well segments in the US has provided a unique opportunity to apply the scientific method to CT interventions because of a reduced number of variables and the fact that the plan/do/check/adjust cycle can be applied. Paper SPE 191689 exemplifies the use of the scientific method for in-well CT operations. Another way to bring efficiency to operations is through the sharing or compounding of data to increase the sample group. Conflicts of interest or fair-competition concerns can make this approach difficult. One paper in the recommended additional reading list, SPE 194277, may offer a practical solution. Part of the operational challenges for CT in unconventional wells is the lateral length that must be accessed. Paper SPE 194300 also shows that these challenges are being encountered similarly offshore and how they are being addressed. Additionally, the continued development of high-performance CT steels and workstring designs (paper SPE 194255) drives these significant enabling technologies in meeting the challenges. The continuing general trend to operate with larger-diameter CT at higher tensile loads brings other operational issues, such as avoiding imparting mechanical damage to the CT’s surface by handling the equipment. Examining how the CT injector might be optimized by design, or by usage, from a finite-element-analysis and a mathematical perspective is discussed in paper SPE 194254 and introduces an interesting factor to the discussion. I am sure that there will be diverse opinions on this work. SPE 194300 Highly Engineered 2.375-in. Coiled Tubing Provides Effective and Reliable Interventions on 30,000-ft Megareach Wells Offshore Abu Dhabi by Irma Galvan, Global Tubing, et al. SPE 194277 Remote Monitoring and Modeling of Coiled-Tubing Operations in Real Time by Paul Brown, CoilData, et al. SPE 192000 Rigless Intervention To Secure Internal Blowout Monitoring Gas Wells Offshore Brunei by Axemi Leong, Halliburton, et al.

Application of X-ray CT scan to slab cores for extracting Cenomanian rudist fossils in Offshore Abu Dhabi as a state-of-the-art nondestructive testing methodology

Application of X-ray CT scan to slab cores for extracting Cenomanian rudist fossils in Offshore Abu Dhabi as a state-of-the-art nondestructive testing methodology

Development of an oil field in an environmentally sensitive area offshore Abu Dhabi

Development of an oil field in an environmentally sensitive area offshore Abu Dhabi

Imaging high-resolution velocity and attenuation structures from walkaway vertical seismic profile data in a carbonate reservoir using visco-acoustic waveform inversion

Frequency domain visco-acoustic waveform inversion is applied to multi-offsets vertical seismic profile data acquired over a carbonates reservoir in an oil field offshore Abu Dhabi in the United Arab Emirates, to produce high resolution seismic velocity and attenuation structures. The starting velocity and attenuation models are obtained from traveltime tomography, and from the centroid frequency-shift method, respectively. Waveform tomography is performed between the frequencies 4 and 50 Hz. To reduce coupling between velocity and attenuation parameters during model updates, a two stage inversion strategy is adopted. During the first stage, only the velocity model is recovered and, during the second stage, velocity and attenuation models are recovered. The density is estimated from empirical correlation derived from sonic and density logs at the borehole location. A judicious selection of the time-damping constant [Formula: see text], used to suppress late arrivals in the Laplace-Fourier domain is critical to mitigate nonlinearities. Prior to the inversion, data preconditioning is done to transform the data in a form convenient for the visco-acoustic wave equation. High resolution final velocity and attenuation models are obtained. Extracted 1D profiles from the final models generally correlate well with the sonic log and estimated clay content from the gamma-ray log. These observations give confidence to the results. A comparison of the synthetic data generated from the final models and the field data shows a high degree of similarity. The high resolution of the results enables us to readily identify layers and provide a geologic interpretation from Quaternary to Late Jurassic. The inverted models show a stack of layers with alternating relatively high and low velocity values associated with relatively high- and low-attenuation values defining anticlines, as we progressed deeper into the subsurface. The two main reservoirs units in the Lower Cretaceous are clearly identified.

Technology Focus: Subsea Hardware and Technology (August 2018)

Technology Focus A long-standing truism is that ideas that change one industry dramatically often are the result of innovations from a different industry altogether. In the realm of subsea exploration and production, with its high levels of risk and expense, concepts pioneered or used elsewhere are positioned to initiate important advances, a fact reflected in the three papers chosen for this year’s feature on Subsea Hardware and Technology. Paper OTC 28051 uses the strength, weakness, opportunity, and threat (SWOT) analysis technique often used in organizational and personal strategy-building to compare four different development concepts that hold promise for meeting the environmental and economic challenges posed by presalt fields in the Santos and Campos basins. In its discussion of fiber-communications technology that has been widely used in other industries, paper OTC 27987 describes the search for optimal use of wet-mate connectors in subsea applications, stressing that the significant opportunities in data collection offered by this hardware are of limited value without rigorous quality control. Finally, paper OTC 29069 delves into the world of marine mining, where developments in artificial intelligence and robotics are redefining the roles of autonomous underwater vehicles (AUVs). These innovations, including diverse aspects such as increased mobility and manipulation abilities and enhanced inspection capabilities for extended AUV missions, may increase cost-effectiveness while creating minimal disruption to the seafloor—innovations that will likely have a powerful echo in the oil and gas industry. With hard work, the progress outlined in these three papers may help create a better balance between cost, production, and ecological stability in offshore operations. The papers illustrate the inter-dependence of both technological and environmental systems, a truth of which operators in all realms of the industry must remain perpetually aware. Recommended additional reading at OnePetro: www.onepetro.org. OTC 28992 Horizontal Well Placement in a Thin Heterogeneous Carbonate Reservoir Using Azimuthal Sonic and Resistivity Measurements: A Case Study From Offshore Abu Dhabi by Amr M. Serry, ADMA-OPCO, et al. OTC 28562 Electric-Controls Technology: The Role in Future Subsea Systems by Sigurd Moe, TechnipFMC, et al.