Unconventional assets are crucial to the overall economic production of hydrocarbons. With the industry-wide trend of optimizing well spacing comes an increase in “frac hits”, i.e., adverse impacts on producing wells from stimulating a nearby well. Although in-zone frac hit events do not necessarily pose an environmental problem, data shows that existing, producing wells can be negatively impacted in a number of ways. Producing wells can be harmed when the pressure wave created during the hydraulic fracturing process is strong enough to cause pressure spikes or sand loading, either directly through fracture/fracture interactions or indirectly due to the propagating pressure wave reaching a nearby well drainage boundary with enough energy to cause damage. Consequently, finding ways to minimize the effect of fracture hits is currently a major focus in the oil and gas industry. In this paper, we consider an approach to mitigating frac hits that can be applied when initially performing acreage planning by ensuring sufficient well spacing during pad planning, or at stimulation time by limiting fracture lengths so that fractures do not directly interact with nearby producing wells.
Drilling, completing and stimulating unconventional wells requires significant capital investment. Because unconventional assets are becoming increasingly more important, there is an industry-wide tendency to maximize acreage production by optimizing well spacing in unconventional reservoirs. However, reduced well spacing has led to “frac hits”, here defined as unwanted interactions between a hydraulically stimulated well and a nearby producing well. Given the amount of in-fill drilling currently afoot in the industry (Vidma et al. 2019), and the number of future horizontal wells forecasted to be fractured (Cook et al. 2016; Perrin, et al. 2016; Cook et al. 2018), the issue of frac hits has become of significant concern. Field data demonstrates that producing wells can be negatively impacted in several ways. For example, the pressure wave created during the hydraulic fracturing process can interact with the existing well drainage boundary either directly or indirectly. Direct interactions include fracture/fracture interactions such as strong pressure spikes or fracture clogging, and may include interactions via fracture networks as well. Indirect interactions may occur when the hydraulic stimulation-induced pressure wave propagates through the porous subsurface and reaches a nearby well with enough energy to cause damage. Damages can occur to downhole artificial lift equipment, through sand loading or pressure spikes, or manifest as production re-routing from one well to another or as production re-distribution within a well.
Baker Hughes drilled one horizontal well for major Indian operating company in a, low resistivity contrast field, onshore India. The candidate field / basin is a proved petroliferous basin, located in the northeastern corner of India.
The scope of work for this project involved integrating geological and open hole offset parameters to build a Geosteering model. Integrated data included a study of offset well data from the field, regional and local dip analysis from wellbore images, and a review of structural maps. Successful integration of these data helped to steer the well in the desired zone as per plan and make the best use of the data and to reduce uncertainties in Geosteering, drilling. Although high-quality 16-sector images commonly yield bedding dip, fracture and other geological information, this paper emphasizes how real-time reservoir navigation decisions was made using Geosteering modelling, real-time image processing, dip picking study etc.
Shiwang, Rahul (Baker Hughes, a GE company) | Banerjee, Anirban (Baker Hughes, a GE company) | Ramaswamy, Vijay (Baker Hughes, a GE company) | Malik, Sonia (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company) | Kumar, Sanjeev (ONGC Ltd.) | Chadha, A. K (ONGC Ltd.)
The identification of fluid saturations in depleted reservoir sands is critical to understand the reservoir potential and field life. However, in case of water flooding, the formation water salinity of the reservoirs sands might be altered and fluid saturations from conventional petrophysical analysis can be misleading. This will have direct impact on the field economics. A salinity independent saturation computation from Carbon/Oxygen (C/O) log becomes a necessity in such development wells– a first of such application in a field under secondary recovery for this basin.
C/O well logging has been extensively used in cased hole environments to determine saturation behind casing. They are used essentially to determine oil saturation in cased hole conditions for depleted reservoirs. While their cased hole applications have been well established; for the study well, a pulsed neutron tool was used in an open hole environment to determine the fluid saturations to compare against the saturations computed from conventional resistivity logs. This study helped in the determination of fluid saturations in mixed salinity reservoir sands, which were to be explored from subsequent wells in the field.
The hydrocarbon-bearing sands in the field were water injected in nearby wells to enhance recovery. Development wells drilled in the field relied on petrophysical evaluation from conventional open hole data and pressure testing and fluid sampling depths were determined accordingly. A pulsed neutron tool was deployed in an open hole well after operational constraints were encountered with the formation testing tool. As an alternative, the pulsed neutron data were acquired in the well to compute salinity independent water saturation based on C/O log response as against the fluid saturation computation from resistivity logs. The determination of fluid saturations from C/O helped in determination of altered salinity for the sand intervals in the field. For the study well, C/O-derived water saturation was found to be higher than that from resistivity log computation. This was significant in identification of water breakthrough in the bottom interval of the reservoir sands.
This paper details the method and findings of C/O logging in open hole environment from Western Onland Basin in India. The critical solutions provided for the reservoir sands in the field and enabled the operator to save significant well cost and rig time by making informed decision of not lowering the casing in this well section.
Saha, Sankhajit (Baker Hughes, a GE company) | Gariya, Bhuwan Chandra (Hindustan Oil Exploration Company Ltd) | Panda, Debabrata (Hindustan Oil Exploration Company Ltd) | Perumalla, Satya (Baker Hughes, a GE company) | Podder, Tuhin (Baker Hughes, a GE company) | Thanvi, Shrikant (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company)
Drilling through the thick shale sequence (Oligocene to Paleocene age) of Cauvery offshore showed severe wellbore instability in the past due to incompatible mud program that increased overall operational cost. While new high-angle sidetrack development wells had been planned, three major challenges need to be addressed. First, proper mud weight recommendation for preventing mechanical instability; second, introduction of a cost-effective mud system preventing time-sensitive failure; and finally, mitigating the environmental impact factor of the mud system.
Geomechanical modelling and Hole Stability analysis had been performed based on available dataset. An optimized mud weight (MW) program was developed based on the analysis. Considering the time-dependent failure characteristics of the shale and overall cost effectiveness, just modifying the mud weight does not address all of the challenges delineated above. Consequently, special "high-performance water-based mud system (HPWBM)" was designed instead of oil-based mud (OBM). This HPWBM was formulated based on the nature of shales encountered. While drilling, real-time geomechanics further facilitated controlled drilling conditions and optimized the mud program.
The well-based geomechanical model indicated a hydrostatic pore pressure gradient in the region. The relative magnitude of three principle stresses showed a normal fault stress regime and maximum horizontal stress (SHmax) azimuth appeared to be nearly aligned to the N-S direction. Hole Stability analysis showed that a minimum of 12 ppg mud weight was required to drill the 8½" section. The sidetrack holes had a maximum inclination of 75 to 77 degrees. Different polymers and bridging agents were added to prepare the customized HPWBM in order to address shale instability and formation damage due to overbalance. Real-time monitoring during drilling operation utilized logging while drilling (LWD) log data, drilling parameters and mud logging data to promote smooth drilling operations. Through systematic planning and execution, the high-angle sidetrack holes had been drilled with zero non-productive time (NPT) in terms of well bore stability. More than 50% cost reduction was achieved on the mud system.
An integrated solution that includes pre-drill geomechanics, HPWBM system design and real-time well monitoring helped to reduce the risks due to model uncertainties while drilling high angle wells through the thick shale section. This approach helped to reduce significant operational cost with an improved success rate.
Lu, Jian (Shell International Exploration and Production Inc) | Toups, Dale (Shell Exploration & Production Company) | Lamoureux, Burton (Shell International Exploration and Production Inc) | Williams, Stephen (Malvern Panalytical) | Williams, Joshua (Baker Hughes, a GE company)
Water, oil and solid field sample characterizations are essential to scale management, corrosion and flow assurance surveillance. From sample collection to getting lab test results take weeks to even months for off-shore locations, while operation changes can happen in hours or days. During the sample transportation process, water and solid samples are often oxidized with iron species dropped out of solution or changed to oxide. For fast operational feedback and "freshest" sample measurement, on-site composition analyses are highly desirable. Typical lab analyzers, such as ICP (inductively coupled plasma) and IC (Ion Chromatography), are highly specialized and requires regular chemical supplies and maintenance. So many lab analyzers are not suitable for on-site use.
This paper reports the development of test methods using a benchtop X-Ray Fluorescence (XRF) analyzer for oil field samples and field application at Gulf of Mexico offshore locations. The Benchtop XRF analyzer is very user-friendly, requires minimal sample preparation, and leaves little room for human error. Once set up, the analyzer provides fast on-site feedback at low cost, and can work with all non-gas samples. With calibrated methods, this analyzer can provide quantitative measurement for elements in water or oil. For other sample types, such as solid, slurry, mix and metals, this analyzer can be used to do qualitative measurements for trending and component identification.
This on-site surveillance tool has proven to be able to provide fast and accurate data on key elements for scale, corrosion and flow assurance management at a low cost. Examples of operation decisions based on this analyzer results will be presented. This tool has demonstrated the ability to provide timely data for preventing plugging/fouling, checking chemical effectiveness, improved integrity surveillance and well flowback surveillance. Use of this tool during maintenance/turnaround helps to build up a better picture on areas with various deposits.
Yang, Xudong (Baker Hughes, a GE company) | Bello, Oladele (Baker Hughes, a GE company) | Yang, Lei (Baker Hughes, a GE company) | Bale, Derek (Baker Hughes, a GE company) | Failla, Roberto (Baker Hughes, a GE company)
The Oil and Gas (O&G) industry is embracing modern and intelligent digital technologies such as big data analytics, cloud services, machine learning etc. to increase productivity, enhance operations safety, reduce operation cost and mitigate adverse environmental impact. Challenges that come with such an oil field digital transformation include, but are certainly not limited to: information explosion; isolated and incompatible data repositories; logistics for data exchange and communication; obsoleted processes; cost of support; and the lack of data security. In this paper, we introduce an elastically scalable cloud-based platform to provide big data service for the upstream oil and gas industry, with high reliability and high performance on real-time or near real-time services based on industry standards. First, we review the nature of big data within O&G, paying special attention to distributed fiber optic sensing technologies. We highlight the challenges and necessary system requirements to build effective and scalable downhole big data management and analytics. Secondly, we propose a cloud-based platform architecture for data management and analytics services. Finally, we will present multiple case studies and examples with our system as it is applied in the field. We demonstrate that a standardized data communication and security model enables high efficiency for data transmission, storage, management, sharing and processing in a highly secure environment. Using a standard big data framework and tools (e.g., Apache Hadoop, Spark and Kafka) together with machine learning techniques towards autonomous analysis of such data sources, we are able to process extremely large and complex datasets in an efficient way to provide real-time or near real-time data analytical service, including prescriptive and predictive analytics. The proposed integrated service comprises multiple main systems, such as a downhole data acquisition system; data exchange and management system; data processing and analytics system; as well as data visualization, event alerting and reporting system. With emerging fiber optic technologies, this system not only provides services using legacy O&G data such as static reservoir information, fluid characteristics, well log, well completion information, downhole sensing and surface monitoring data, but also incorporates distributed sensing data (DxS) such as distributed temperature sensing (DTS), distributed strain sensing (DSS) and distributed acoustic sensing (DAS) for continuous downhole measurements along the wellbore with very high spatial resolution. It is the addition of the fiber optic distributed sensing technology that has increased exponentially the volume of downhole data needed to be transmitted and securely managed.
In planning for their first TLP deep water project in Malaysia, Shell faced the unique challenge of drilling ERD wells in soft unconsolidated sands with narrow ECD margins. Prior experience suggested the benefit of managed pressure drilling & an additional casing profile with hole enlargement to be implemented for these wells. The formation is also believed to be time sensitive, and reducing the wellbore exposure time between drilling and running liner was considered a priority.
A full suite of LWD services were also planned to be run on these sections, resulting in potentially a very long rat hole as the conventional reamer can only be placed above LWD tools. An additional hole opening trip to minimize rat hole length was not desirable, which in turn leads to concerns of well bore stability due to time exposure as highlighted earlier, as well as increasing potential risk of side tracking in the soft interbedded formations. Flow rate restrictions due to the pressure drop requirements from conventional reamers, was not desirable so as to maintain ECD stability.
In order to address the needs and challenges above, contractor proposed a dual digital reamer solution, in order to ream and drill the hole sections in a single run. The digital reamers, each being powered by the LWD suite, were activated via downlinks, eliminating the lengthy time required by drop ball reamers at high angles. The ability to downlink on demand and perform selective reaming without any pressure drop restriction, had provided added benefits while drilling in narrow ECD margin. As placement of the digital reamers are flexible within the LWD tools, dual reamers were deployed in the BHA. The top reamer located above the LWD tools was activated while drilling to ensure necessary LWD data quality was obtained. A near bit digital reamer was activated post-drilling to eliminate the long drilling rat hole, resulting in minimal rat hole achieved similar to the outcomes of a dedicated trip. Eliminating the dedicated trip also greatly minimized the risk of unintentional side track.
The use of dual digital reamers enabled safe and problem-free drilling, logging, casing and cementing; allowing all of Shell’s objectives to be met in a single run, as well as significant exposure time of the wellbore, up to 3.5 days over 3 hole sections and costs savings, up to 1.2mil USD.
Zhu, Haiwen (University of Tulsa) | Zhu, Jianjun (University of Tulsa) | Zhou, Zulin (University of Tulsa) | Rutter, Risa (Baker Hughes, a GE company) | Forsberg, Michael (Baker Hughes, a GE company) | Gunter, Shawn (Baker Hughes, a GE company) | Zhang, Hong-Quan (University of Tulsa)
As one of the most widely used artificial lift methods, electrical submersible pumps (ESPs) have been improved gradually since the 1910s. However, its performance and run life are affected by many problems such as gas lock, high viscosity fluid, corrosion, and erosion. With the development of horizontal well drilling and multistage hydraulic fracturing, sand production from unconsolidated sandstone and proppant backflow often cause severe damage to ESPs resulting in reduced operating lifespan. Measuring wear in an ESP pump and monitoring performance degradation is not only very difficult in field cases, but also in experimental studies. The results are precious for understanding the wear mechanism inside an ESP as well as guiding the ESP design and simulation. At the same time, vibration and performance data can provide significant guidance to ESP failure diagnosis, which can potentially reduce the time and cost of well service and extend ESP run life.
Wear processes inside an ESP can be classified by different modes of mechanisms. Erosive wear can be observed in the primary flow channel of the impeller (rotor) and diffuser (stator). Particle strike shroud surfaces and the scratched material is flushed away by fluids. Various semi-mechanistic erosion equations are available to be coupled with Computational Fluid Dynamics (CFD) to predict the erosion in ESPs. In the secondary flow region, balance chamber and sealing rings, particles are presented between the stator and the rotating rotor. Therefore, abrasive wear is believed to dominate the wearing process. Unlike erosion, abrasion is more complicated and abrasion equations are highly depended on geometries, physical mechanism and load between particle and target surface. In this study, a sand wear test flow-loop is designed and constructed to investigate wear in ESPs. Performance degradation, Erosion pattern, abrasion rate, and stage vibration of an ESP were recorded in a 64-hour sandy flow test.
Younessi, Ahmadreza (Baker Hughes, a GE company)
The failure around the wellbore is studied using a modified form of Drucker-Prager failure criterion (MDP). The MDP has a linear shear failure envelope in the meridian plane and a curve-sided triangular failure curve in the deviatoric plane which can be controlled by the yield stress ratio (
The MDP is used for stress modelling and wellbore stability analyses. The stress modelling is done by calculating the magnitude of maximum horizontal stress (SHmax) from the observed failure in the image log. The stress modelling result is compared with the results from the Mohr-Coulomb (MC), Drucker-Prager (DP), and modified Lade (MLa) criteria. The MDP is also used for wellbore stability analysis using both analytical and numerical (finite element) approaches. The analytical approach is used to conduct a sensitivity analysis to investigate the impact of well trajectory on minimum required mud weight. The finite element analysis is conducted to investigate the dimension of the breakout developed under different mud weights. The results are compared against the other failure criteria.
The SHmax magnitude calculated from the MDP model falls between the MC and DP. The analysis shows that the MDP with
The results from the finite element analyses shows that the calculated breakout widths and depths using the MDP model falls between the MC and DP models. The analysis shows that in the presented case, although the calculated breakout width is large, the depth and amount of failed material around the wellbore are relatively small to create any wellbore instability problems. Hence, a mud weight relatively lower than calculated required mud weight from the analytical approach can be used in practice to drill the well. The results show the importance of considering the depth of the breakouts in the mud weight design.
One major challenge with the current subsurface modeling workflows is the difficulty to transfer the high complexity of static geological models to simulation. This paper describes an improved gridding technology that overcomes the shortcomings of existing corner-point stair-step and pillar-based grids in capturing the complex geological features of hydrocarbon reservoirs. It also highlights the seamless use of this new gridding technology in flow simulation.
The reservoir's geologic features are initially interpreted as 3D surfaces that are later connected to form structural models. The volume between these surfaces is then discretized into a grid object in order to represent the petrophysical, fluid, and flow properties. This paper introduces a new orthogonal, semi-structured gridding algorithm that uses a truncated cell approach to precisely capture the geometry of faults and unconformities.
After reviewing the different types of grids commonly used in geological modeling, the benefits of the new approach will be detailed, while highlighting its compatibility with commercial flow simulators.
Common modeling practices that use corner-point stair-step and pillar-based grids fail to preserve the geometry of most geological objects. This is especially true in highly faulted and erosional environments. The new gridding algorithm presented in this paper addresses three major shortcomings of the current approaches by providing an efficient way to: Accurately represent any type of geological structures in a 3D grid. The appeal of the technique is its simplicity. The gridding algorithm relies on three components only: a surface-based structural model, a stratigraphic model and a 3D cell resolution. Capture complex sedimentological geometries across geological structures. Several examples are provided to highlight the way the orthogonal, semi-structured grid handles geostatistical simulations. Connect the grid to commercial flow simulators to preserves any type of structure and sedimentology in dynamic simulations.
Accurately represent any type of geological structures in a 3D grid. The appeal of the technique is its simplicity. The gridding algorithm relies on three components only: a surface-based structural model, a stratigraphic model and a 3D cell resolution.
Capture complex sedimentological geometries across geological structures. Several examples are provided to highlight the way the orthogonal, semi-structured grid handles geostatistical simulations.
Connect the grid to commercial flow simulators to preserves any type of structure and sedimentology in dynamic simulations.
This is the first high-accuracy gridding system that is designed to be simulator agnostic. This means that the approach is open and flexible enough to be used by any commercial flow simulators, giving simulation engineers a unique opportunity to run models without the need for any explicit grid system conversion.