The scope of this work is to introduce a technology that measures perforation effectiveness on a stage by stage basis before the hydraulic fracturing process begins. The measurement utilizes surface generated tube waves to interrogate the perforated section of the wellbore. We present three case studies demonstrating how "low perforation quality alerts" mitigate operational issues, achieving the deployment of appropriate stimulation treatments for several operators in the Eagle Ford, Haynesville, and Niobrara formations. The reflections of tube waves are analyzed to characterize perforation effectiveness on a stage by stage basis. This methodology is non-intrusive, infinitely repeatable and can be performed in the short time interval between removing the perforating equipment from the well and beginning the fracture treatment process. The operators in our study were alerted to stages with a high likelihood of pumping issues such as high treating pressure, screen outs, or low proppant volume placement. Real-time measurements flagged these stages as having poor wellbore connectivity to the reservoir. Prior to pumping, the operator and crew in the field were alerted to the stages that showed low perforation quality. This allowed modifications to the stage design, such as additional acid, sweeps, finer proppant, gel, increased pad, lower rate, or an additional perforation run. In the cases where changes were made to the design, the objective of mitigating pumping problems due to poor perforation performance was a success. In all the cases where preventive design changes were not implemented, downhole difficulties were experienced resulting in sub-optimal stage execution and/or screen outs. Cost savings in the range of $300,000 on some wells were achieved due to the mitigation of pumping problems associated with poor wellbore to reservoir connectivity. Perforation quality and reservoir rock geomechanics play a dominant role in hydraulic fracturing operational success or failure. Although there have been extensive studies focusing on the role that perforation diameter plays on treatment efficiency, these studies do not adequately consider the importance of the perforation tunnel (depth and quality of perforation penetration into the near well region). Having real-time, non-intrusive, field-based data that provides a direct measurement of this essential element can influence the execution of the hydraulic fracture design. This mitigates the costly exercise of recovering from a screen out and improves the likelihood of a productive stage.

Unexpected problems during completion create costs that can cause a well to be outside its planned AFE and even uneconomic. These problems range from merely experiencing abnormally high pressures during treatment to casing failures. The authors of this paper use machine learning methods combined with geomechanical, wellbore trajectory, and completion datasets to develop models that predict which stages will experience difficulties during completion. The operator collected geomechanical data for 26 lateral wells. Several of these wells experienced significant difficulties during completion, including casing failures. By examining the completion data for the study wells, engineers developed two objective proxies for trouble stages: a high fracture gradient cut-off and a sand-to-water ratio cut off. The geomechanical data were combined with wellbore trajectory and stage-level completion data. Machine learning techniques were then used to predict the fracture gradient at the end of treatment and the sand-to-water ratio of a stage. The data were subdivided by target horizon to ensure the model results were not skewed towards a specific horizon. The models were cross validated, hyper-parameter tuned, and then tested against a subset of the data withheld from the training algorithm (the test data subset). Multiple metrics were applied to measure the effectiveness of the models. For the fracture gradient regression, the model that minimized the root mean squared error (RMSE) was chosen. This model was compared to a prediction that each stage would have a fracture gradient equal to the average fracture gradient. The correlation between predicted and measured frac gradients was also calculated. These metrics were analyzed for both the entire data set and the test data subset. By all these measures the model performs significantly better than the control prediction. For the sand-to-water ratio metric, the model that maximized the receiver operating characteristic area under the curve (ROC-AUC or AUC) score was chosen. We chose to measure the success of the model with the precision of its prediction of outlier (trouble) stages on the test data subset. The model performs with a precision of at least 73%. Both models identify stages where casing failures occurred as trouble stages. With these initial results, the authors are confident they can predict the probability of any stage causing a significant operational disruption in these horizons. By predicting the probability of a trouble stage, mitigation plans can be implemented to reduce costs ahead of time. By further analyzing the models, engineers can identify the major drivers for the trouble stages and work to reduce them as early as the well planning stage.

Improving pumping system efficiency in low production wells has been a big challenge for most of mature fields in China. These wells often cause high energy consumption and additional mechanical wear because of relatively high pumping speed and nonoptimalpower input for motor drive, even though operators respond it by simply turning down the stroke per minute (SPM) or adopting variable intermittent production scheme based on the well conditions. Therefore, for low production wells, it is important to produce more oil with lower energy input or operational cost. In recent years, researchers proposed a few high-efficiency intelligent control strategies used for these wells, but rarely could be effective and widely used in the field due to the lack of behavior improvement and adaptability. Based on the results from previous research, this paper provides a new solution on flexible variable frequency drive to address the aforementioned challenges. To obtain high system efficiency for low production well, firstly new solution, under a preset and fixed SPM, manage to change pumping speed within each cycle. This can be done utilizing the pumping net load data which is calculated by controller algorithm. Then, it will regulate the SPM based on the real time production data (mainly for fluid rate) which is automatically collected by a specialized wellhead flow meter. Since flow rate is the most effective and direct data to demonstrate reservoir capacity, it can guarantee an accurate and reasonable pump SPM. All adjustments above would be done through continuously regulating the motor electrical parameters, such as voltage and current, using converter and control algorithm built in the flexible controller. Real-time matching to the lifting load and well capacity can realize the best motor drive pattern and avoid the waste of energy. Tow set of process control makes up the new control strategy and fulfills a more ideal pumping operation. For different well capacity, new technology allows the pump frequency to be regulated from 0.5 SPM to 12 SPM under a stable running condition. Each stroke has an adjustable rate process to match inconstant net load. For those low production wells, relatively low and constant-changing pumping speed not only largely decrease producing energy needs, but also reduce rod-on-tubing wear. Thus, the test wells have improved system efficiency and prolonged mean time between failures (MTBF). This paper would describe the control principle of flexible variable frequency drive system in detail and demonstrate its application through two well cases.

The objective of the present work is to streamline the analysis of Lease Operating Statements (LOS) with advanced learning paradigms from artificial intelligence (AI). The proposed approach aims at the: (a) consolidation of disparate expenses data; (b) timely expense assessment at field, pad or well level; (c) prevention and quick identification of negative cash flow trends (d) robust LOS predictions; and (e) optimal budget planning under uncertainty. To achieve this objective, a LOS acceleration platform was developed for the automatic integration of volume estimation with Lease Operating Expenses (LOE). Historical data from production volumes, revenues, price differentials, LOEs, marketing and transportation costs, taxes, CAPEX, P&A costs and others considered to strengthen the accuracy of individual expense categories and the overall LOS predictive model. The predictive model consists of a combined blend of analytical and machine learning models that allows to reliably forecast trends and proactively detect anomalies that may be negatively affecting the operational cash flow. Intuitive and portable visualizations allow a quick interpretation and communication of results among engineers and managers. The implemented platform fills a gap between traditional LOS analysis and preemptive expense planning involving many wells and expense categories that are hard to track daily. It is shown that the proposed approach can lead to savings of the order of 30% in incurred expenses.

A new, fully automated completion system contributed to improved safety and efficiency of plug and perforate completions on 34 horizontal wells completed in west Texas Delaware Basin between 2018 and 2020. By enabling nearly continuous frac operations and wireline transitions in three minutes or less, the new system helped reduce the average time-to-complete a well by 38% compared to the average performance on the operator's nearby wells completed using a traditional latch.

Wells in the Permian Basin continue to increase in technical complexity and lateral length, testing the limits of traditional completion practices in unconventional wells. Coiled tubing has been the standard method for drilling out frac plugs in the basin but has mechanical limitations in extended-reach and high-pressure laterals. Due to the increasing well complexity operators have begun using high technology hydraulic completion units (HCU), also known as a snubbing unit, to drill out frac plugs in certain Permian Basin wells. By using the HCU in wells with longer laterals, higher pressures, and downhole uncertainty/complexity some of the additional risk can be mitigated. The HCU system can provide a reliable and cost-effective means to cleanout laterals in the Permian Basin while reducing mechanical risk. The purpose of this paper is to present case histories that illustrate the positive impact of the HCU on field operations. This paper will also detail the evolution of the HCU over time to its current state of the art stand-alone rigless system.

The driller on the rig performs a number of complex tasks including engaging and disengaging the bit, determining subsurface bit location in real-time, orienting the toolface to steer the bit, adjusting pumps and rotary, and deciding set-points to maximize performance, all while managing the rig crew to ensure safe operations. There is always a potential for dynamic dysfunctions that, if not addressed quickly, could have destructive outcomes. Stick-slip, bit whirl, excessive downhole vibration, and oversteering can each quickly lead to problems. Human response time to address these phenomena varies greatly. Further, the methods in which drillers address these dysfunctions are not standardized. This human variability can increase well costs, decrease production potential, and increase safety risks. Under the direction of experienced drillers, a suite of software applications has been developed to provide a holistic, automated solution to many of the tasks previously performed manually by humans. Reducing human variability bridges the gap between past performance and maximum theoretical performance. Deployment of these "apps" within an autonomous drilling platform enables operators to easily study and improve the drilling process and, in turn, accelerate and improve well programs.Utilizing multiple automation technologies simultaneously improves consistency, reduces operating costs and lowers risk potential. Higher quality wellbores are delivered with maximum hydrocarbon production potential. New processes have been developed to deploy the apps in a coordinated way, changing roles both in the field and in 24/7 remote support centers. The apps automate or augment many processes, such as making connections, making slide/rotate decisions, determining bit position in relation to local geology, reengaging the bit to bottom, and controlling both rotating and sliding sequences in an efficient manner. Individual automation technologies have demonstrated measured benefits independently. However, the utilization of an entire suite of automation tools designed to work together within new workflows has demonstrated a substantially higher benefit potential to the operator not typically achievable by individual automation technologies in isolation. These human/machine workflows were refined in pilot deployments and are now being deployed at various levels across a uniform fleet of rigs. Individual tasks can be automated in relation to acquiring and analyzing data, making decisions, and implementing those decisions as part of the drilling processes. Automation empowers the operator by allowing significantly larger volumes of data to be digested and interpreted more rapidly than is possible by humans alone, while taking economic factors into account during the automated decision making. The deployment of the automation technologies presented in this paper requires novel work processes both in the field and in the office that are only possible across a uniform suite of rigs, demonstrating the value of scaling and leveraging expertise and experience.

Completion diagnostics have been extensively utilized in hydraulically fractured horizontal wells across all major basins to determine the effectiveness of stimulation strategies and to evaluate new technologies. They have also been key in understanding factors that drive well performance and reduce completion costs. Geological heterogeneity provides unique challenges and opportunities for completion optimization. Diagnostic data provide insights into fracture characterization under various geological conditions and how they can be utilized for well design and field development. This paper demonstrates the integration of geology with completion diagnostics results. The dynamic relationship between evolving completion technologies and geology is brought to light with the help of case studies across multiple basins. The challenges studied include fracture driven interactions (frac-hits), perforation cluster design, landing zone optimization and production analysis. By incorporating geology into the diagnostic results, additional insights are obtained for enhanced reservoir characterization and future field development. The case histories illustrate how the interpretation of diagnostic data can be strengthened by a combined understanding of geology and completion technologies, instead of employing an independent approach. In one instance, a high degree of fracture driven interactions (frac-hits) from new completions to existing producers was observed. Further detailed study of geological features in the section revealed that the frac-hits were primarily due to the presence of the faults rather than by well proximity and stimulation treatment volumes. In another example, diagnostics data identify low hydrocarbon productivity across several stages within a well. The load fluid recoveries in these stages with low hydrocarbon flowback are comparable to better performing stages, indicating effective stimulation and flow capacity within the fracture. This underscores the importance of comprehensive lithology evaluation across the lateral to identify low productivity intervals, for improving future well placement and performance. The outcomes of these case studies provide examples of the barriers between engineering and geology being broken through data corroboration. Asset level decisions surrounding the integration of multiple technical teams offer an opportunity to reduce the learning curve in basin development strategies. This study releases case studies across multiple basins that leverage this integration. The approach outlined in this paper can be applied in any horizontal field development program.

With the advent of robust and powerful IIoT Edge Devices, it is now possible to deploy Machine Learning models at the boundaries of a production network, i.e. using Smart Nodes directly at the wellhead that runs analytics in near real-time. These Smart Nodes, when paired with Augmented Intelligence capabilities, allow subject matter experts to interact with Machine Learning models and help improve their accuracy over time. This, in turn, helps increase confidence in data-based results and enables operators to make informed decisions. This paper will define and discuss an end-to-end architecture on how Augmented Intelligence, in tandem with Edge Analytics, can be implemented in the upstream production environment. Results, methodologies and lessons learnt from an Edge Analytics solution deployed on Rod Pump wells will be discussed in this paper.

In the ultradeepwater oil and gas market, operators demand reliability and efficiency in all technical disciplines involved during the entire life cycle from exploration through decommissioning stages. In the perforating segment, specifically, recent technological advancements have allowed service companies to increase electric line (e-line) and tubing-conveyed perforating (TCP) gun footage to save rig time. E-line perforating capacity for 7-in. guns has increased from 15 to 41 m/run (49 to 135 ft/run), while the 4 ⅝-in. gun capacity has increased from 20 to 50 m/run (66 to 165 ft/run). This paper discusses how such advancements led to new benchmarks for perforating footage during deployment of a large gun system in Brazilian presalt, changing the perforation technique, and ultimately reducing operational expenses. During perforating, excessive shock loads are applied on the weak point (WP), so the challenge was to develop a perforating system that could increase the effective perforating footage using 7-in. and 4 ⅝-in. guns without damaging the e-line or dropping the guns because of a pull off. A specially designed WP for high dynamic loading, together with a new 2 ¾-in. outer diameter (OD) cable head was developed. Various software simulations were run to analyze the shock-loading effects on the cable and WP during run in hole (RIH), gun detonation, and pulling out of the hole (POOH). This paper presents seven field case studies in which this new technology was applied. High-speed memory recordings of pressure and radial/axial accelerations were used to acquire actual downhole data during the perforating event to compare with simulation results and calibrate the models. The WPs were analyzed to validate the overall response of the new perforating system. The actual surface tension and downhole data, such as pressure and acceleration, matched the simulation results. During the seven field case studies, the new perforating system using e-line deployment helped improve rig-time efficiency, saving more than 130 rig hours compared to performing the operation using the traditional TCP service, representing more than USD 2 million overall savings. The capability of running long sections of large guns is a significant achievement for wireline-deployed perforating services. During the Brazil operation, the increased efficiency resulted in a reduction of 16 hours of completion phase, which equates to a savings of hundreds of thousands of dollars when compared with TCP operations.

The act of planning a well is a collaborative effort taking disparate data from various groups and synthesizing it into one overarching program. Each operator follows its own well design process, but common to each operator is the fact that wells not designed wholly in series, but rather have many parallel sections, with a set of decision gates and countless data interdependencies. The goal of this paper is to detail the successful development and implementation of an integrated planning platform within a National Oil Company. The individual components of well design process are not performed in a vacuum. The various inputs / outputs from one application affect the inputs/ outputs of applications both upstream and downstream of it, along the design process. This is addressed by facilitating integration and analysis of data input / output from each component of the planning process, synthesizing it, and performing automated system-integrity and overall conformity checks between the interdependent components. Any changes to an individual design component that affect other areas must be flagged, notifying the appropriate parties. Defining and automating workflows, mapping data interdependencies within the workflows, and creating a system of data governance are also keys to building an efficient planning platform. Similar to a navigation program which is able to determine an optimal driving route by considering various dynamic and static data points, the implemented platform uses a data-adaptive approach to well planning. Using this method, it takes unstructured data processes, decision trees, data integration protocols, and automates them while also permitting users to collaborate on well planning and design, allowing the standardization of processes. Operators are able to embed their particular methods of well design into the software platform and thus ensure that all of their company meet the specific requirements. Key to the effectiveness and longevity of this type of platform is a neutral data repository. Allowing data to be free of any singular data protocol ensures that although individual applications may revised, replaced, or put into competition with one another, the format of the data produced as well as ingested by these applications stays constant. Data will remain mapped, both in terms of overall process workflow and interdependencies. This paper is beneficial to any operator wishing to gain insight in developing a forward thinking of a digital strategy for well planning and design. However, the use of these types of methods and development of a similarly integrated platform an operator can standardize processes, enforce and ensure data governance, as well as gain efficiency in overall planning time.

Injector well completions are typically carried out using two methods: simple and selective. The performance of injector wells has traditionally been evaluated using spinner-based injection logging tools (ILTs) or on-demand fiber optic distributed temperature and acoustic (DTS or DAS) sensing while logging the well performance every 3 months or once a year depending on the application. However, with such methods utilizing a snap shot approach, critical well performance information or possible anomalies are often missed due to measurements taken only during certain periods. Therefore, operators have explored the use of advanced fiber-optics methods such as permanent distributed temperature sensing (DTS) and permanent distributed acoustic sensing (DAS), that provide continuous, real-time measurements to enable understanding of dynamic well behavior at all times and mitigate any deferred or behavioral problems. Of relevance to this work is a vertical, injector well in a competent sandstone formation of the Heavy Oil Chichimene field in Llanos Basin, Colombia. As a first step of the fiber-optics monitoring strategy, a careful evaluation of DTS and DAS based fiber-optics methods was conducted. Based on the data analysis and operational history, DAS-based fiber optics monitoring was chosen as the most effective monitoring solution for this well. Subsequently, a proprietary DAS algorithm was developed to analyze the data and estimate the flow allocation for all the four zones. The results include waterfall acoustic energy maps, temporal flow allocation profiles and most importantly, the zonal flow allocation values. Predicted (DAS) zonal flow allocation data was compared with traditional injection logs (ILT) under different operational conditions (varied injection flow rates and valve choke settings). Based on comparable agreement between DAS and ILT data, the operator decided to replace ILT runs with DAS-based fiber optic monitoring, resulting in lower operational costs while enabling near real-time monitoring, and providing the continuous distributed data essential for the dynamic monitoring of the well. The successful application of fiber-optics monitoring to provide an injection profile in conjunction with a surface-controlled electric valve system demonstrates a significant potential to optimize the injection process in complex injector wells. Further, remotely controlling, monitoring and optimizing injection rates into the multi-segmented zones improves the service life of the injection operations, eliminates future intervention costs, and increases ultimate recovery.

Permian operators have dramatically increased the number of multi-stage fractured horizontal wells over the past 5 years and face challenges associated with maximizing production of existing wells while developing new acreage and benches, all the while meeting capital return requirements. Over that time, DNA diagnostics have been applied successfully to more than 1000 wells throughout the Permian Basin to help operators reduce uncertainties ranging from drained rock volume, well-well communication, and sources of water production. When subsurface conditions change, microbes change, and the DNA from microbes can be used to profile total fluid flow (water + oil phases) from benches and between wells. It therefore serves as a powerful tool to provide a range of answers, using advanced analytics and integration with various data sets. In this study, we will provide the background of DNA diagnostics and related analytics, along with the latest insights into viable operating environments. We also highlight recent Permian basin projects that have used DNA in conjunction with operator data to reduce uncertainty about subsurface conditions. We will show Total Fluid Logs, which are based on comparing DNA signatures from produced fluids with a DNA stratigraphy log. Total Fluid Logs are utilized to 1) constrain interpreted fracture heights, and 2) work in combination with pressure and production data for Rate Transient Analysis (RTA) for significantly improved estimation of the half-length. The case histories will illustrate the differences between production rates and confirmed fracture height and half-length, and a discussion of microseismic is included. We show how produced fluid collection during pad completions can elucidate well-well communication and demonstrate the impact of completion size and completion order on effective drainage heights. DNA changes in produced fluids can be compared to production data to reveal the timing and impact of frac hits between wells during zipper completions. Finally, we provide a suggested workflow for analyzing water contributions out of target in the diagnosis of problem wells. Petrophysical logs can be compared to drainage height assessments to help reveal from which depths water may be producing and can be integrated with production data for a more complete subsurface understanding. DNA diagnostics represent a complementary, cost effective, minimum environmental footprint and low risk tool for operators to easily integrate into existing production and engineering workflows for monitoring well health and subsurface conditions across time.

Technology to interrogate perforations to quantify cluster efficiency in limited entry, plug and perf completions has improved in operational efficiency, image quality and quantity. The entire pipe wall of the lateral is now visually imaged, and the discovery of significant casing erosion damage caused by leaking frac plugs during stimulations is easily observable, often multiple times in the same well. The effect of a breached casing with significant erosion between stages could potentially divert proppant from the intended perforation targets leading to reduced cluster efficiency and uncertainty of proppant distribution results. Video images have been used for several years to evaluate proppant distribution. The recent introduction of array side-view camera technology now provides highly detailed images of the full 360 circumference of the wellbore over extended intervals. Image logging methods for unconventional wells have changed from capturing a limited number of images of individual perforations through a small ‘spy hole’ to a complete panoramic view of the entire wellbore. Perforations, connections and everything in between can be efficiently imaged and analysed. Enhanced processing methods have additionally improved visualization of results and allowed quantification of areas of interest with image-based dimensioning. Greatly enhanced borehole image coverage has allowed the discovery of unintended interactions that can be very detrimental to fracture treatments. Evidence of these unwanted effects that were previously difficult to diagnose are now uncovered during routine fracture diagnostics. Evidence includes Erosion at plug setting depths has been observed in a relatively high proportion of wells Multiple casing breaches have also been observed in some wells with as many as 35% of plug setting depths subject to this issue The areal extent of erosion at plugs has been measured in the range of 10% of the casing circumference up to 100% full parting While the exact effects on the fracture treatment of potentially large volumes of fluid and proppant being diverted away from their intended target has not yet been quantified the catastrophic effect on well integrity is very clear. Examples, analysis methods, results, primary conclusions, and other relevant findings are discussed in detail. The technology we discuss is undoubtedly helping raise awareness in the industry of the potential extent of this previously under-diagnosed issue. Increased awareness and improved understanding of the issue will lead operators to better equipment selection, enhanced procedures and ultimately more productive and profitable wells. Hydraulic fracture performance will improve while cases of compromised well integrity will decline.

This paper presents the development of a real-time gas monitoring system with alerts transmitted to the office domain, and the team leads whenever the gases are detected. The system monitors the presence of the hazardous H 2 S gas. It sends signals to the control room in the manned plants so that operators can take the necessary precautions when stepping into these locations. It also sends alerts to the office domains when the permit to work is being prepared for any facility. It provides a continuous real-time update of the gas present in the location to a cloud-based platform. This is beneficial as it will enable plant operators to take the necessary precautions to both protect themselves and also protect the facilities if the gas discharge spreads across the plant's zone classifications

Solid Expandable Tubular (SET) usage in drilling applications of oil and gas wells has traditionally spanned drilling challenges such as covering up unstable formations due to pressure variations, isolate sections with losses or wellbore intrusions, maximizing Inner Diameter (ID) of the liner at Total Depth (TD) to improve Equivalent Circulating Density (ECD) of the next cementing operation. A bigger ID also gives room for higher production rates due to lower pressure through prod tubing. As operators are looking to cut well costs, well designs are optimized with as few casing strings as possible to get to TD. Solid expandable liners have customarily been considered a contingency only to be installed in case problems arise. The operational envelope of expandable liners has broadened over the years with the introduction of high torque expandable connections and rotation-enabled expandable liners which has allowed the liners to be run in more complex scenarios and in increasingly challenging down hole applications. Operators have started becoming aware of the fact that expandable liners can play a bigger role as a planned-in and permanent tool in the operational tool box. One such area is multilateral wells where reservoir contact can be greatly increased by drilling multiple sections through the reservoir from one mother-bore. By using existing casing infrastructure operators can drill additional reservoir section(s) without drilling completely new wells, saving both time and money. One major North Sea operator recognized a potential to utilize an expandable liner in a multilateral application, and have completed the first two wells validating this solution for constructing multilateral junctions from an expandable liner run and expanded out of a milled window in 10 ¾ in. casing. The post-expanded drift of the expandable liner allowed for drilling of an 8 ½ in. mainbore out of the expanded liner shoe, and an 8 ½ in. lateral branch sidetrack with a pressure seal multilateral junction installed. Length requirement of the expandable liner was estimated to be from 500 to 1000m as the solid expandable liner would need to isolate the gas zone, although it was not required to act as a permanent barrier. During the pre-validation phase connection gas testing was performed, as well as post-expanded wear testing in order to simulate liner wear from drilling two 6000m long reservoir sections. The next test well was planned with two multilateral junctions allowing for a total of three reservoir sections. This paper details the innovative approach a major North Sea operator took to multilateral wellbore design utilizing the SET system in three distinct ways in the same installation; 1) as a means to temporarily isolating the gas zone in the reservoir in order to drill the oil zone, 2) utilize the SET system as host casing for a multilateral junctions and 3) to isolate existing perforations in the 10 ¾ in. casing.

Shale producers in North America continue to face challenges with paraffin wax deposition in well bores, production tubing and flowlines as production declines and artificial lift methods such as gas lift are applied. Preventative measures are often based on traditional screening and assessment methods which rely on crude’s wax appearance temperature (WAT). Recent studies have shown that operators are increasingly turning to costly remediation program and stimulation jobs to maintain production rates as oil wells decline at faster rates than anticipated. It appears in many cases that these declines can be exacerbated by downhole organic fouling and wax deposition that surprisingly may have occurred above the original WAT. This paper aims to conduct a root cause analysis to identify the key internal and external factors impacting an oil’s WAT. Four crude oils and field wax deposits from Gulf of Mexico, South Texas and West Texas areas were used for this study. Due to the unique composition of the field deposits and depleted crude sample available for analysis, a novel strategy for lab screening was adopted. Crude oil samples were examined "as received" and after reconditioning via the addition of solvents and/or field deposits. Further measurements were performed to identify and quantify the effects of the addition of production chemicals particularly hydrate inhibitors. A series of dispersion and deposition tests were then conducted in order to demonstrate the potential impacts of incompatible chemistries. Fractionation based on solubility revealed a dynamic behavior for the WAT of crudes that corelated to their paraffin content and distribution. Samples containing C 45+ paraffin chains demonstrated significant WAT changes upon reconditioning. The addition of methanol and MEG typically used as hydrate inhibitors, impacted the WATs of the crudes as measured by DSC showing increases in the WATs compared to unconditioned samples. An additional suite of dispersion and deposition testing conducted on the same samples supported the findings of the DSC studies. A nonlinear correlation was found between increasing WAT and paraffin deposition rate. The approach outlined in this paper provides a more accurate field condition simulation leading to more effective inhibitor selection and ultimately improved flow assurance management in more complex production systems. The methodology of mimicking hydrocarbon fluid behavior was the key factor identified by the root cause analysis and correlated to the series of past failures attributed to organic fouling. WAT was found to be a parameter that can vary for a crude oil over the life of a production system. With the current evolution of shale oil production in North America and around the world, we expect these findings will also be relevant to unconventional production and will aid the oil industry to anticipate and manage previously unforeseen problematic paraffins in production systems.

Recent industry analysis based on publicly available production data of most unconventional basins in the US have consistently highlighted the underperformance of child wells as compared to parent wells, although completion practices have continuously evolved. Industry publications have suggested that average productivity degradation of child wells can be up to 29% for some Delaware Basin operators. In some cases, the detrimental effects of parent-child relationships have also been observed on the parent wells after the stimulation of the child wells. In such an environment it is important to develop completion strategies to mitigate the negative effects of this parent-child relationship. In the Delaware Basin, the negative parent-child effect was successfully mitigated on two different zipper pads, with parent wells as close as 500 ft away from the zippered child wells. On the first pad, one parent well was completed and six months later two child wells were zippered with the closest child 1,000 ft away from the parent and pumped with far-field diversion. On the second pad, one parent well was completed and four months later three child wells were zippered with the closest child well 500 ft away from parent and far-field diversion pumped on the two closest child wells. The stimulation treatment design was carefully designed to include far-field diverters on the stages near parent wells. Job size and far-field diverter quantity were determined using an integrated hydraulic fracture simulation software with an advanced particle transport model. Contingency scenarios were also prepared to facilitate real-time changes required when or if abnormal behavior was observed during the execution. The zipper sequence was also planned to help establish a stress-shadow effect near the parent well to further mitigate detrimental parent-child interactions. To monitor execution in real time and evaluate interactions between wells, high-frequency pressure gauges were installed on all observation wells including parent and child wells. The completion design and far-field diversion treatment worked as planned for the first pad, with no significant well interference pressure signature observed on the monitoring well. For the second pad, the parent well saw pressure increases up to 700 psi during the treatment of a stage midway along the lateral of the closest child well which was completed with far-field diverter. Contingency plans were successfully executed, and no significant pressure increase was observed on the remainder of the lateral. Early production results indicate that the negative impacts of parent-child interactions were successfully mitigated on both pads, with the production of the parent wells quickly returned to their observed trends prior to child wells stimulation. Child wells production, when normalized both by lateral length and stimulation size, was on par with that of the parent well.

The Eagle Ford Shale play has undergone significant development over the last decade, with indications that there is still room for additional development. As operator's move to non-core areas there is a need for additional optimization to effectively drain these new areas. This paper studies trends emerging from a post-stimulation completion diagnostics database, comprised of over 10 years of data, to help identify factors associated with effective horizontal completions in the Eagle Ford shale. By employing data analytical techniques to the horizontal well database, critical production performance metrics and insights associated with effective completions are presented. Coupled with this, case histories are also included that illustrate techniques that have increased overall completion effectiveness in relation to proppant placement, cluster treatment efficiency, stage containment, well deliverability, wells spacing/frac size optimization, and ultimately increased production performance. The case histories also highlight the effects of completion optimization on limiting production declines as operators move into non-core acreage over time in most North American shale plays, and more specifically the Eagle Ford shale.

This paper will discuss the Managed Pressure Directional Drilling fit-for-purpose solution deployed to meet the drilling challenges faced in 5 consecutive wells drilled in South Texas, USA. This innovative solution integrates a state-of-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as well control events, simultaneous kick-loss, and stuck pipe were mitigated, and an improved drilling performance with a reduction of NPT as compared to other directional drilling systems. The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling. Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication protocol are crucial for effective execution. The solution is based on a rigorous Drilling Engineering process, including detailed offset wells analysis to deliver a comprehensive risk assessment & mitigation plan in collaboration with the Operator to tackle drilling hazards without compromising the directional drilling requirements. This paper will summarize the 5 wells operations, the drilling optimization results, and the lessons learned from an integrated services point of view in terms of deliverables that made the difference on this project and allowed the Operator to achieve their objectives. In particular, the effective communication protocol between the directional drilling services, MPD services, and rig contractors to ensure safe operational alignment.