Rig Time Research Articles

Near-Real-Time Tracer Data Optimizes Well Cleanups in the Nova Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214351, “Near-Real-Time Tracer Data From the Onsite Tracer Analysis in the Nova Field,” by Alireza Roostaei, SPE, Ehsan Nikjoo, SPE, and Ali Nadali, SPE, Resman, et al. The paper has not been peer reviewed. _ This paper describes how near-real-time tracer data from an onsite tracer analysis enabled the operator to interactively optimize two well cleanups in the Nova field. The tracers provided key information on the cleanup progress in different zones, which enabled the operator to make informed and fast decisions to maximize well-cleanup efficiency while minimizing rig time and cost. Introduction The Nova field is in the northeastern North Sea. Reservoir sands are at depths of 2500–2800 m, with a pressure of approximately 290 bar and temperatures up to 110°C. The field will be operated with six wells—three oil producers and three water injectors—with an injector/producer pair in each of the main fault compartments. The authors, in the complete paper, show the value of inflow tracer data during the cleanup phase of two producers (X-3H and X-4 AHT2) in the field. Well-Cleanup Challenges and Monitoring Requirements The main challenge is to ensure that the well is sufficiently cleaned up at the zonal level while rig time and cost is minimized. Therefore, a monitoring method is required that can provide real-time data of cleanup progress in different zones. The data enables the operator to make informed decisions while the cleanup is ongoing, allowing optimization of well cleanup when needed. The risk-free and cost-effective inflow tracers with onsite analysis provide near-real-time data on cleanup efficiency in different zones. Because the Nova wells are equipped with inflow tracers, the operator used this data to understand the wells’ behavior and make real-time decisions to increase cleanup efficiency and zonal productivity. Equipment and Processes Inflow tracers are integrated in polymer rods that are stable in a wide range of well conditions. These inflow (in-well) tracers have been tested and designed in different hydrocarbon fluids and a broad temperature range (20–200°C). In the Nova field, unique oil and water tracers were deployed in the lower completion. These intelligent tracers remain dormant until they come in contact with their target fluids. Oil-based mud (OBM) was used as a lower completion fluid in the Nova oil wells; thus, the release of oil tracers began with contact with OBM. The polymer tracer rods are installed in the completion before running in hole; therefore, no downhole intervention is required. Each unique oil-tracer system consists of several polymer rods distributed evenly around the pipe in a carrier. The venting configuration of these systems is shown in Fig. 1. Once the tracers are released from the polymer rods, they will travel to surface with the fluid flow. At surface, samples are taken with different sampling frequencies depending on the monitoring objectives. The samples then are analyzed in a laboratory to identify and quantify tracers. The samples can be analyzed onsite or offsite.

Changing the Game: Well Integrity Measurements Acquired on Drillpipe

The industry is continuously challenged to improve the efficiency and safety of operations. This is evident over the last 30 years in the development and improvement of measurements acquired while drilling. However, this has, in general, until now not been applied to well integrity measurements such as casing integrity and cement evaluation, which have traditionally been acquired utilizing wireline deployment. This paper will show the results of a new drillpipe-deployed tool that can be run in parallel with existing well operations. The results from two differing North Sea wells will be compared to traditionally acquired wireline-deployed tools and will demonstrate that these measurements and the resultant interpretation can successfully be acquired on drillpipe. This allows for much improved efficiency of operations and, in fact, the ability to acquire this important data in well conditions and environments where it is difficult or, in some cases, impossible to log with conventional wireline techniques. Two wells were selected with different degrees of difficulty in terms of measurement acquisition and showing different well trajectories and mud types. Both wells were logged with both the new drillpipe-deployed technology and traditional wireline technology, allowing a direct comparison of the techniques and tools and paving the way for acceptance of the new drillpipe-conveyed technology. The new drillpipe-conveyed tool can be run anytime drillpipe is utilized in the well. A radial distribution of ultrasonic transducers arranged on the circumference of a drill collar allows for full azimuthal interpretation of the casing and cement while rotating the drillpipe. Analysis of the acquired data allows for the interpretation of caliper thickness and an evaluation of the material in the annular space behind the casing. In addition, the tool can provide casing collar location in real time and has the ability to orient downhole devices such as whipstocks, perforating guns, and oriented cutters. The two well examples conclusively demonstrate that the tool can be run in parallel with existing operations to minimize rig time and eliminate the need for a dedicated, standalone wireline operation. Also, the cement evaluation interpretation was comparable to the equivalent wireline technology. We will investigate which measurements and applications the new tool can be used for and where there may be further room for improvement.

AI, Influencers, and Grit: How Apache’s 8-Year Quest To Build Its Own Drilling Advisor Achieved Full Adoption

When oil prices tumble, upstream research and development projects are among the first casualties. Many are put on the shelf. Few are ever taken off. Then there’s what happened at Apache Corp. More than a decade ago, the Houston-based independent oil and gas producer, which following a restructuring is now a subsidiary of APA Corp., was among a small cadre of operators working at the fore of automated drilling technology. As a first adopter, Apache had gone so far as to develop a newbuild automated rig design for its onshore shale fields in Texas. Then in mid-2014, crude prices plummeted nearly 60% over a 7-month period. The heady days of $100/bbl oil were replaced by the era of “lower for longer,” derailing Apache’s ambitious plan to build its pioneering prototype. That could have been the end of the story. But less than a year after the ambitious capital project was scrapped, something else emerged in its place. While AI-based automation was out, Apache’s drilling team was given a chance to develop the next best thing: an AI-based drilling advisory system. “We saw that there was at least a small opportunity to do something more with our rig data—that 1-Hz real-time data—by combining it and mashing it up with contextual data so that it could be something useful,” said Michael Behounek, a former director of drilling, completions, and workover performance and leader of the project for Apache where he spent the past 13 years before taking early retirement. Now a managing partner of an upstream digital consulting startup called Emerja, Behounek spoke at the recent SPE Annual Technical Conference and Exhibition while presenting SPE 215132. The paper outlines how after 8 years that small opportunity turned into a 10% year-over-year reduction in drilling costs. The system, a presumed multi-million dollar value creator, was adopted across all of Apache’s contracted rigs in 2018, playing an increasingly important role in the drilling of more than 1,700 wells across a wide spectrum of geologies. This track record spans nine onshore and offshore basins, with deployments of the system in the Permian Basin, Egypt, Canada, offshore Suriname, and the North Sea. Behounek said most of the reported cost savings stem from the models’ ability to trim rig time by predicting problems that would keep drillers from staying on bottom and turning to the right. That said, the paper, which is coauthored by Apache’s software partner Intellicess Inc., emphasizes that “the system only enables the opportunity—it is the field personnel and engineers taking the proper actions and decisions offered by the system that deliver the improvement.” Apache has shared several papers about the various components of the advisory program over the years but the most recent offers a holistic view of the strategy that led to companywide adoption. Of the dozens of takeaways it offers, some of the biggest follow.

Geochemical Approaches Assist Production Allocation of Commingled Fluids

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205130, “The Application of Petroleum Geochemical Methods to Production Allocation of Commingled Fluids,” by Richard Patience, Mark Bastow, and Martin Fowler, Applied Petroleum Technology, et al. The paper has not been peer reviewed. _ Geochemical-based methods for production monitoring and allocation are much lower-cost than use of production logging tools because no additional rig time or extra personnel are required at the well site. Additionally, no intervention to the production of hydrocarbons from a well is required, reducing operational risk. The complete paper summarizes these approaches and provides examples and describes a best practice that avoids a one-size-fits-all approach. Introduction Production allocation from petroleum geochemistry is defined here as the quantitative determination of the amount or portion of a commingled fluid to be assigned to two or more individual fluid sources at a particular moment in time based on fluid chemistry. It requires knowledge of the original chemical compositions of each of the fluids before mixing (referred to here as the “end members”) and the ability to identify statistically valid differences in their chemistries. The fluid may be oil, gas, or water. The concept is illustrated in Fig. 1a by mixing colors to represent the end members and commingled fluid. Production monitoring, in contrast, is the analysis of a time series of production fluids from the same source. This is demonstrated in Fig. 1b, where a change in chemistry can be observed between Days 60 and 100. Two data points at the same time are duplicates, proving that the change in chemistry is real and not an artifact. It is generally qualitative to semiquantitative in comparison with production allocation. Production allocation, therefore, is inherently more complex, in terms of both the sample requirements and data treatment. Allocation is the main focus of this paper. Allocation Sampling Strategies For a production allocation project, the three following distinct stages require samples: Stage 1: Can Contributing End Members Be Distinguished? In the initial stage, a determination must be made regarding whether end member reservoirs contributing to production can be distinguished based on their chemical composition. End Members From Conventional Plays. These typically are flowed samples from drillstem tests, bottomhole samples from wireline tools, or production tests, usually taken during the drilling of exploration or appraisal wells. Several issues must be considered when assessing the usefulness of such samples: - Are the end member samples representative of the reservoir as a whole? - Is the end member sample contaminated with organic compounds from drilling fluid? - When were the end members taken, how were they stored, and has there been significant alteration of the composition of the sample as a result?

FACILITATING MUD DESIGN, CEMENTING JOB DESIGN AND THE ENTIRE DRILLING OPERATIONS BY MODELLING THE RHEOLOGICAL PROPERTIES OF WATER-BASED MUD AND OIL-BASED MUD WITH TEMPERATURE

The increasing rental cost of drilling Rig and the associated painful cost of downtime during drilling operations are some of the major concerns of the oil & gas companies. Improper rheological properties of drilling mud may cause a variety of problems including insufficient cuttings transport, limited solids suspension, poor hole-cleaning and excess filtrate loss into the formation. Facilitating mud design, cementing job design and the entire drilling operations will save Rig time and associated cost and prompt management of oil & gas companies to devote more of their useful time and resources to other significant aspects of their operations. The aforesaid prompted this work to invent a method for developing mathematical models representing the rheological parameters of drilling mud (water-based mud and oil-based mud) to enable prediction of the rheological properties in emergency situations where and when Laboratory services are not immediately available. The methods applied include Laboratory testing and mathematical modelling. Results revealed that the mathematical models can be confidently applied to predict the Plastic viscosity and Yield stress of water based mud and oil-based mud as the correlation coefficient (R-squared value) obtained for each of the aforesaid rheological properties was higher than 95% Therefore, as the rheological properties of water-based mud and oil-based mud depend on their composition, physical and chemical properties, mathematical models should be proactively developed for the Plastic viscosity and Yield stress for every mud in hole to enable prediction of the its rheological parameters when and where laboratory services are not immediately available.

Challenges and Practices for Recovering Stuck Coiled Tubing Pipe

Summary Stuck coiled tubing (CT) is a main operational risk leading to delays, deferred production, or even the loss of a well. Despite general commonalities, each CT recovery can face unique challenges, including managing high pressure, working under limited spatial or lifting constraints, establishing well control, or handling a cable inside the CT. This study consolidates learnings and proposes a general workflow for a basic stuck pipe scenario, rig up, recovery pressure control equipment (RPCE) and well control, CT free point evaluation, bottomhole assemblies (BHAs) and workflows for cutting and freeing the CT pipe downhole, and recovery of the CT at the surface. A consolidation of published case studies provides specific examples of the hardware, workflows, and operational considerations. In addition, the presentation of a recent case study extends the discussion to the challenges introduced by the presence of a cable in the stuck CT and its respective solution. The case study reviews the planning and execution of a CT recovery, including the use of decision trees to guide the decision-making process. It details fit-for-purpose hardware for safely anchoring the cable; packoffs for accessing, tensioning, and recovering it with slickline (SLK); an opening for deploying the wireline (WL) cutting BHA; and valves for pressure testing and well control. That workflow successfully freed 6,818 ft of stuck CT and allowed recovery of the pipe without a workover rig on location, eliminating 11 days of rig time during subsequent tubing pulling. This is the first such documented recovery case worldwide based on a thorough literature review.

Evaluation Of Drill Bit Selection On Basement Layer Exploration Drilling In AFM Block

In one of the exploration drilling of the AF-01 well, there was a drilling problem on the 8 in hole when it penetrated the basement layer. ROP at the time of drilling the basement layer is far below the estimated ROP.By setting MSE as, ROP is increased so that cost savings are obtained from reducing rig time. A qualitative analysis of drillbit selection was carried out based on the type and design of the drillbit as well as the characteristics of the basement rock to be penetrated.In addition to the qualitative and quantitative assessment was carried out through the calculation of the PDC Design Index, MSE, DSE and CPF on each drill bit.ROP of Hybrid PDC-1 increased 500% when compared to PDC-1. The MSE and DSE produced by the Hybrid PDC-1 are 750% smaller than the PDC-1. Using the Hybrid PDC-1, drilling costs can be reduced up to USD 2,105,481.The low ROP at the time of drilling the basement layer in well AF-01 was due to the incompatibility of the PDC-1 bit used for the type of rock being penetrated. Hybrid PDC-1 is the most optimum bit to penetrate the basement layer in the AFM Block.

Analyzing average rig time and ease of drilling in Indian sedimentary basins: an informative tool for exploration decision-making

Hydrocarbon exploration entails complex and costly endeavors, with drilling activities accounting for the highest expenses. To facilitate informed decision-making for geoscientists and investors, this study presents a template highlighting the average rig days and drilling ease in Indian sedimentary basins. Leveraging data from over 19,000 wells across these basins, a comprehensive analysis was conducted. While the physics and chemistry of drilling are well understood, uncertainties arise from local geological conditions, well specifications, contractor expertise, timely rig availability, market factors, and local regulations. By filtering out extreme rig times affected by these factors, average rig time (ART) and average total depth (ATD) were calculated for each basin using a simple averaging approach. ART was visualized as a basin-wise bubble map, providing an overview of the drilling duration required to reach total depth. This aids in estimating drilling costs for future wells in relatively unexplored areas. Additionally, a contour map incorporating basin-wise ATD was generated, offering insights into structural variations and basement configurations. Combining ART and ATD, a single factor known as the ease of drilling (EOD) was calculated and presented as a bubble map across Indian sedimentary basins. This map serves as a valuable tool for investors, providing information on the optimal depth and duration of drilling in each basin and aiding decision-making processes for exploration projects.

Integrated workflow for rotary sidewall cores orientation: best practices and examples from planning to execution

Over the last five years, the acquisition of rotary sidewall cores has become increasingly important in the O&G business. It is a matter of fact that the current tendency is to prefer them as a replacement to bottom hole cores, essentially for rig time related cost saving. This fact leads to force their use also for those types of characterisation usually reserved to larger size samples so, by consequence, some specific issues associated to their small size and to the lack of knowledge of in situ orientation have to be faced. For several applications such as geomechanics (whose experimental analysis require vertical plugs), petrophysics (permeability anisotropy, natural fracture orientation) and sedimentology, the original orientation, or its a posteriori identification, is mandatory in order to correctly measure properties relevant for reservoir management and studies. The full orientation of rotary sidewall cores requires to acquire or compute three couples of spatial information: high-side and low-side, wellbore end and formation end, trend and plunge of the samples. A dedicated workflow to a posteriori reconstruction of the orientation of large size rotary sidewall cores has been developed by means of the integration of multiple scale imaging techniques: images from logs and sidewall core are integrated through commercial software usually adopted for dip analysis. This approach has been successfully applied to several sidewall cores gathered in different geological environments. Currently, new coring and conveyance technologies allowing a predetermined sidewall cores orientation are emerging, increasing the reliability of the orientation workflow. Therefore, different scenarios of log planning strategy, operational solutions and post-coring analysis can be expected, depending on the confidence in the geological-structural interpretation and on the complexity of the technical environment. In all cases, it is extremely important to plan specific data acquisition and handling operations from wellsite to laboratory; including formalized minimum requirements and dedicated procedures, in order to maximize the quality of the subsequent laboratory analyses.

Surgical Coiled Tubing Stimulations: Step Changes in Effectiveness, Efficiency, and Characterization of Waterflooding Interventions

Summary An innovative coiled tubing (CT) real-time flow measurement tool was introduced in Ecuador to reformulate the stimulation workflow in water injectors, which comprised evaluation and treatment. This new technology enabled an integrated, single-run workflow instead—initial injectivity measurements, diagnostics, treatment, post-stimulation injectivity measurements, and final diagnostics. This novel, rigless approach reduced equipment footprint, operational time, and cost, and it improved production as compared with the conventional approach, despite accrued capital discipline constraints. Conventionally, operators rely on workover rigs and multiple product lines to diagnose, stimulate, and evaluate injector wells. Several challenges and inefficiencies were addressed by deploying the CT real-time flow measurement tool. Each intervention was designed to be completed with a single CT run and without the need for a workover rig, thus saving cost and time. Tailored diversion methods substituted the need for drillpipe to set mechanical packers. Prestimulation injection logging test (ILT) results obtained with that innovative tool, coupled with real-time control of depth and high-pressure jetting during execution, enabled effective placement of the stimulation treatment. Ultimately, post-treatment ILTs confirmed treatment effectiveness and final wellbore downhole conditions. Introduction of the CT real-time downhole flow measurement tool allowed operational objectives to be met in a single run, without additional interventions, with or without a workover rig on site. When workover rigs were present, this improved workflow saved an average of 15% operational time. In cases without a workover rig, 105 hours of rig time were saved (without considering rig mobilization time). Four case studies are presented. The first two cases demonstrate how acquisition of ILTs throughout the intervention enabled optimization of fluid placement and introduction of diverter methods. The third case covers a scenario where there was an initially low injectivity and highlights the challenges and lessons associated with recovering injectivity. The fourth case presents challenges unique to flowmeter measurements in heavy-oil environments. In each case, effectiveness of the optimized treatment was measured by two metrics: improvements in net injectivity and uniformity of injection profile, both of which drive the effectiveness of secondary recovery in connected producer wells. On average, wells intervened with this approach featured an improvement in injectivity of 301% (compared with 226% conventionally) and in their injection profile homogeneity by 13%. As a result, the productivity in connected wells improved by as much as 74% and an average of 39% (compared with 14% conventionally). This innovative workflow is a step change over conventional approaches to rejuvenate waterflooding. It combines the capabilities of delivering treatments via CT and the power of real-time downhole flow measurements to break the paradigm of multiline, multirun operations to remediate and stimulate injector wells. This yields logistically leaner operations, which are less costly, and it enables breakthroughs in secondary recovery through data-enriched interventions in times of budget pressure, not only in Ecuador, but also across the globe.

Electrical Heating Can Optimize Production in Heavy-Oil Fields With Intelligent Multilaterals

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 20134, “Production Optimization Through Intelligent Multilateral Wells in Heavy-Oil Fields by Electrical Heating,” by Cenk Temizel, SPE, Saudi Aramco; Celal Hakan Canbaz, Ege University; and Fatma Bahar Hosgor, Petroleum Software, et al. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. Electrical resistive heating provides key advantages over other thermal methods in the recovery of heavy-oil resources. However, the recovery efficiency with electrical heating is relatively lower compared with more-conventional methods such as cyclic steam stimulation, steamflooding, and steam-assisted gravity drainage (SAGD) because it does not introduce a (pressure) drive mechanism and the radius of effect is relatively small, which may result in marginal economics. In this study, the application of electrical resistance heating on multilateral wells is studied in order to illustrate the enhanced physical and economic benefits of the method in such a setting. Smart Tools in Multilateral Wells Placement of a multilateral well is a decision that must be considered carefully. The easiest method of determining whether the approach is the right one for a field is to analogize multilateral wells with the traditional single-bore wells that penetrate to the same formation area. The multilayered well has less drilling depth and reduced rig time compared with the conventional wells. Thus, multilaterals are an advantageous completion design in locations such as offshore platforms or harsh-weather areas. However, multilateral well-completion design is challenging because of its increased complexity. Most smart wells include hydraulic-control systems to satisfy a simpler, more-reliable operation. Current wellhead-control systems allow a limited number of penetrations. The indications are that smart tools controlled with electrical systems will be an emerging focal point of the industry. The cost of a multilateral well is higher because of the equipment used and operational complexity. It also includes a higher risk compared with the risk of a conventional well. Any problem that results in abandoning the well will bring a major economic loss equal to the cost of several conventional wells.

Seismic-while-drilling by drill-bit source and large-aperture ocean-bottom array

Seismic-while-drilling (SWD) by drill-bit source has been successfully used in the past few decades and is proven using variable configurations in onshore applications. The method creates a reverse vertical seismic profile (RVSP) data set from surface sensors deployed as arrays in the proximity of the monitored wells. The typical application makes use of rig-pilot reference (pilot) sensors at the top of the drill string and also downhole. This approach provides while-drilling checkshots as well as multioffset RVSP for 2D and 3D imaging around the well and prediction ahead of the bit. For logistical (sensor deployment) and cost (rig time related to technical installation) reasons, the conventional drill-bit SWD application is typically much easier onshore than offshore. We have developed a novel approach that uses a network of passive-monitoring sea-bottom nodes predeployed for microseismic monitoring to simultaneously and effectively record offshore SWD data. We study the results of a pilot test in which we passively monitored the drilling of an appraisal well at the Wisting discovery in the Barents Sea with an ocean-bottom cable deployed temporarily around the drilling rig. The continuous passive recording of vibration signals emitted during the drilling of the well provides the SWD data set, which is treated as an RVSP. The study is performed without rig-pilot signal. The results are compared with legacy data and demonstrate the effectiveness of the approach and point to future applications for real-time monitoring of the drilling progress, in terms of geosteering the drill bit and predicting formation properties ahead of the bit by reflection imaging.

Completion Design to Remove and/or Replace the Existing Completion in a Well and in Single Trip

The aim of this paper is to propose a completion design to remove and/or replace the existing completion in a well named "X" (for confidential reasons) in a single trip. To reach the goal, the metallurgy and seals of the equipment must be selected by taking in consideration their working pressure and temperature. The best completion method must be chosen amongst others. The data used are well trajectory, particle size distribution, the reservoir data including temperature profiles, pressure, productivity index, water cuts, sand production volumes, formation damage, formation permeability, reservoir thickness and fluid properties. The completion schematic is drawn using Lip-Draw 2017, and the summary installation procedure is explained. The results show that the most appropriate materials were found to be an alloy with 13 % of chromium as metallurgy and hydrogenated nitrile for sealing elements due to the presence of H2S and CO2. For this case, the best completion method is filtrex. By using the filtrex method, the payback period is short and possibility to perform remedial sand control in a single trip while saving rig time. Filtrex method is more economical in this case than chemical and mechanical methods. For the others wells in the same field, similar completion design must be done.

Estimation of Elastic Wave Velocity From Logging-While-Drilling Measurement in Unconsolidated Formation of Accretionary Wedge in Nankai Trough

The logging-while-drilling (LWD) acoustic technology has been developed to measure formation velocities/slownesses for rig time saving and real-time applications such as seismic-tie, pore pressure determination and/or deep-sea drilling exploration. The formation compression-wave velocity is often hard to determine because of the drilling environment and wave dispersion effects. We develop a new model-based dispersive processing (MDP) method to accurately determine wave slowness from the LWD acoustic data. Two specific steps are included during the MDP procedure. In the first, the effective collar parameters are determined using the collar-wave from the measurements. The second step is the inversion for the wave slowness by minimizing the difference between the theoretical curve and dispersion data. We have validated the result of the MDP inversion with synthetic data testing and applied it to the acoustic LWD data of the Ocean Drilling Program (ODP) 808I hole. Applications of the corrected slowness results to synthetic seismogram and porosity prediction analyses demonstrate the effectiveness of the correction method.

An Integrated Petrophysical Characterization of a Siliciclastic Tight Gas Reservoir in Neuquén Basin, Western Argentina

The Río Neuquén Field is located between Neuquén and Río Negro provinces, Argentina. Historically, it has been a conventional oil producer, but it was converted to a tight gas producer from deeper reservoirs. The targeted geological formations are Lajas, which is already a known tight gas producer, and the less-known overlaying Punta Rosada Formation, which is the main objective of the current work. Punta Rosada presents a diverse lithology, including shaly intervals separating multiple stacked reservoirs that grade from fine-grained sandstones to conglomerates. The reservoir pressure can change from the normal hydrostatic gradient to up to 50% of overpressure. There is little evidence of movable water. The key well in this study has a comprehensive set of openhole logs, including pulsed-neutron spectroscopy data, and is supported by a full core study over 597 ft. Additionally, data from several offset wells were used, containing sidewall cores and complete sets of electrical logs. This allowed the development of rock-calibrated mineral models, adjusting the clay volume with X-ray diffraction data, porosity, and permeability with core measurements, and linking the log interpretation to dominant pore-throat radius models from MICP Purcell tests. Several water saturation models were tested, attempting to adjust the irreducible water saturation with NMR and Purcell tests at reservoir conditions. As a result, three hydraulic units were defined and characterized, identifying a strong correlation with lithofacies observed in cores and image logs. A cluster analysis model allowed the propagation of the facies to the rest of the wells (50). Finally, lithofacies were distributed in a full-field 3D model, guided by an elastic seismic inversion. In the main key well, in addition to the openhole logs and core data, a casedhole pulsed-neutron log (PNL) was also acquired, which was used to develop algorithms to generate synthetic pseudo-openhole logs such as bulk density and resistivity, integrated with the spectroscopy mineralogical information and other PNL data, to perform the petrophysical evaluation. This enables the option to evaluate wells in contingency situations where openhole logs are not possible or too risky, and also in planned situations to replace the openhole data in infill wells, saving considerable drilling rig time during this field development phase. Additionally, the calibrated casedhole model can be used in old wells. This paper explores the integration of different core and log measurements and explains the development of rock-calibrated petrophysical and rock type models addressing the characterization challenges found in tight gas sand reservoirs. The results of this study will be crucial to optimize the field development.

Technical Solution Improves Safety, Efficiency of Well Construction Offshore Australia

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202353, “Drilling-Performance and Risk-Management Optimization Offshore Australia: Improving Overall Safety and Efficiency of the Well-Construction Process,” by Chandrasekhar Kirthi Singam, Farshid Hafezi, and Clyde Rebello, Schlumberger, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. The emergence of real-time well construction performance-monitoring centers has improved the service delivery for operators across numerous offshore oil fields in Australia significantly. The complete paper details new technologies and work flows implemented for three Australian offshore wells, with the primary objective of improving drilling efficiency while managing associated risks. Additional objectives included optimizing daily operational performance, thus delivering time savings for the operator and highlighting areas of possible improvements. Introduction The paper describes a successful drilling campaign in a challenging field in the Timor Sea. It describes how data analysis, risk evaluation, and real-time performance monitoring can be influential in saving rig time and project success. As part of this project, a major operator in Australia decided to perform an infill drilling campaign involving three high-angle directional wells (J type) in a saturated, complex field. The campaign design stage was initiated in 2017 with a main objective of delivering the project within authority-for-expenditure (AFE) budget and with planning for all potential challenges. Technical Overview The technical solution (Fig. 1) was deployed using drilling-interpretation software and executed its work flows to achieve the required objectives.

Optimizing Production and Improving Well Accessibility With Expandable Technology

Collapsed tubing occurs when external pressure outside the casing is greater than the pressure inside. There are several circumstances which can lead to a collapse, including high pressure outside the casing during operations such as cement squeeze, pressure testing in the annulus, and when the mud level inside the casing drops due to a loss of circulation. The well location within the rock formation can also have an impact on the potential for collapsed tubing. Seismic activity can cause significant damage to the casing and tubing so careful well design and strict operating procedures are essential to reduce the risk. When the issue does occur, it can create a significantly restricted area in the wellbore and often results in failure to gain access below the collapsed area in a wellbore. This, in turn, can cause extensive nonproductive time (NPT) to remediate the issue. Planned drilling or intervention work is halted, and production may be deferred. In the most severe instances when the casing collapses the well is completely abandoned. While the industry continues to focus on enhancing hydrocarbon recovery from existing wells, these operations must remain economically viable. Therefore, preventing and resolving well integrity and access issues have never been more important. With advancements in expandable technology, it is now possible to reform the restriction in a tubular, enabling the inner diameter (ID) to be opened. This allows for either reinstatement of production back to surface or access to equipment below, permitting operators to resume operations with minimal NPT.Coretrax recently deployed its ReForm wellbore repair tool when an international oil company experienced collapsed tubing in a remote well off the coast of Papua New Guinea. The solution uses hydraulic pressure applied at surface to reform collapsed, oval, or restricted tubulars. Overcoming Traditional Limitations During drilling and production activity, tubing and casing are exposed to a range of axial loads and temperatures as the operator utilizes various methods to reach, and then extract, hydrocarbons from the well. In drilling activity, mud losses can often be encountered through thief zones which leads to a lower mud level. With the consistent pressure outside the casing, the collapse resistance can be affected, resulting in full collapse in the wellbore. Swaging is a conventional and widely used method of repairing collapsed tubing. The process involves a series of swages run downhole to gradually open the collapsed area. It can be done with specialized swage packers or with a hydraulic expandable swage. Both methods provide a bond to the existing casing once properly prepped. The technique can take a significant amount of time to open the area due to the number of different swages required. Each time a larger size is needed, the operator must use significant rig time to trip out of hole. While it can have successful outcomes for repairing damaged areas of well casing or screens for example, due to the weight required in the pipe to swage, this procedure is not suitable for shallow or lateral wells.

Long-Term Performance Assessment of Swell Packers Under Different Oilfield Conditions

AbstractSwelling elastomer seals and packers provide effective zonal isolation in difficult oil and gas fields, resulting in significant savings in rig time and development expenses. Companies involved in petroleum engineering applications provide no information about the longevity or endurance of swelling elastomer packers when exposed to different conditions in the well. This paper describes the design and construction of a test facility for long-term performance assessment of actual full-scale water and oil-swell packers, and the results of the 5-year study. The ten packers are made of three types of swelling elastomers, are kept in crude oil and saline solutions at room and high temperatures, and are exposed to varying high pressures. Regular logs of readings were maintained over the whole study period. Earlier sealing was observed in elastomers immersed in low-salinity water and subjected to high temperature. Rate of swelling was higher in water-based elastomers than in oil-based seals. One packer never sealed completely. Pressurized tubes either retained sealing the whole time or re-sealed after removing of pressure or reducing it to a lower value. Results for the fast-swell and medium-swell elastomer, low- and high-salinity water and crude oil, and low- and high-operating temperatures were mostly in line with short-term tests on laboratory samples published earlier. This unique longevity assessment study can be used by drilling engineers and developers in assessing the suitability of swelling elastomers for target fields and in improving the design of swell packers.

An Integrated Petrophysical Workflow for Fluid Characterization and Contacts Identification Using NMR Continuous and Stationary Measurements in a High-Porosity Sandstone Formation, Offshore Norway

The Alvheim Field in the Norwegian North Sea was discovered in 1998. Two wells were drilled in 2018 in the Gekko structure to confirm oil column height and to evaluate reservoir quality in the Heimdal Formation. A comprehensive wireline logging program, including NMR and formation testing, was optimized to reduce formation evaluation uncertainty. Evaluating fluid properties, oil column height, and reservoir quality were primary objectives. Well A was first drilled on the south of the structure, followed by Well B on the north of the structure. Reservoir quality encountered in both wells was very good, and a project to develop these resources is currently in the selection phase. Formation evaluation uncertainty encompassing pore geometry distribution, permeability, reservoir quality, and hydrocarbon identification are mitigated by studying the nuclear magnetic resonance (NMR) log response. NMR fluid typing has been widely used in the oil industry since the 1990s. NMR fluid typing today is a combination of the contrast of spin relaxation time T1, the spin-spin relaxation time T2 (T1T2), and the diffusivity (T2D) of formation fluids (Chen et al., 2016). NMR fluid typing can be obtained from a continuous log and/or stationary log measurements. This paper showcases excellent, textbook-quality NMR data, as well as the integration of NMR data in the petrophysical workflow. High-confidence fluid properties and fluid contacts are determined. This paper also highlights a comparison of NMR data acquired in stationary vs. continuous depth-based log modes in both wells. The continuous log data quality is equivalent to stationary data, implying continuous log data quality is sufficient for reliable NMR fluid properties evaluation without depending on time-consuming stationary NMR measurements. Reducing logging operations rig time is very advantageous in the North Sea, where drilling rig operations cost is high, and enhanced rig time management is constantly required.

Mud-Gas Breakthrough Equinor Develops Real-Time Reservoir-Fluid Identification

For all that logging-while-drilling has provided since its wide-spread adoption in the 1980s, there is one thing on the industry’s wish list that it could never offer: an accurate way to tell the difference between oil and gas. A new technology created by petrotechnicals at Equinor, however, has made this possible. The innovation could be thought of as a pseudo-log, but Equinor is describing it as a reservoir-fluid-identification system. Using an internally developed machine-learning model, it compares a database of more than 4,000 reservoir samples against the real-time analysis of the mud gas that flows up a well as it is drilled. Crunched out of the technology’s various hardware and software components is a prediction on the gas/oil ratio (GOR) that the rock being drilled through will have once it is producing. Since this happens in real time, it boils down to an alert system for when drillers are tapping into uneconomic pay zones. “This is something people have tried to do for 30 years - using partial information to predict entire oil and gas properties,” said Tao Yang. He added that “the data acquisition is rather cheap compared with all the downhole tools, and it doesn’t cost you rig time,” highlighting that the mud-gas analyzer critical to the process sits on a rig or platform without interfering with drilling operations. Yang is a reservoir technology specialist at Equinor and one of the authors of a technical paper (SPE 201323) about the new digital technology that was presented at the SPE Annual Technical Conference and Exhibition in October. He and his colleagues spent more than 3 years building the system which began in the Norwegian oil company’s Houston office as a project to improve pressure/volume/temperature (PVT) analysis in tight-oil wells in North America. It has since found a home in the company’s much larger offshore business unit in Stavanger. Offshore projects designed around certain oil-production targets can face harsh realities when they end up producing more associated gas than expected. It is the difference between drilling an underperforming well full of headaches and one that will pay out hundreds of millions of dollars over its lifetime. By introducing real-time fluid identification, Equinor is trying to enforce a new control on that risk by giving drillers the information they need to pull the bit back and start drilling a side-track deeper into the formation where the odds are better of finding higher proportions of oil or condensates. At the conference, Yang shared details about some of the first field implementations, saying that in most cases the GOR predictions made by the fluid-identification system were confirmed by traditional PVT analysis from the trial wells. Unlike other advancements made on this front, he also said the new approach is the first of its kind to combine such a large database of PVT data with a machine-learning model “that is common to any well.” That means “we do not need to know where this well is located” to make a GOR prediction, said Yang.