Santos, Hugo (Petrobras) | Paz, Paulo (Petrobras) | Kretli, Igor (Petrobras) | Reis, Ney (Petrobras) | Pinto, Hardy (Petrobras) | Galassi, Maurício (Petrobras) | Pozzani, Daniel (Petrobras) | Lanzilotta, Alessandro (Petrobras) | Castro, Bruno (Petrobras) | Ferreira, André (Petrobras) | Thomé, Lincoln (Petrobras) | Beal, Valter (Senai CIMATEC)
This paper proposes the development of an autonomous robot for rigless well interventions in order to reduce costs by avoiding the need of a rig to do so, especially for light workover operations in offshore locations. It also presents experimental tests performed in a laboratory string and in a test well in order to evaluate the feasibility of this technology.
Barraza, Jesus (Chevron North America E&P) | Champeaux, Chris (Chevron North America E&P) | Myatt, Heath (C&J Energy Services) | Lamon, Kyle (C&J Energy Services) | Bowland, Ryan (Spartan Energy Services) | Bishop, Troy (Coil Chem LLC) | Noles, Jerry (Coil Chem LLC) | Garlow, Rocky (RGC Consulting LLC)
As drilling and fracturing operations improve and wells have longer laterals, there is a need to adapt current Coil Tubing Unit Drillout (CTUDO) process to be more fit-for-purpose approach applicable in any area, regardless of lateral length, number of plugs, and reservoir target. This paper presents the CTUDO methodology developed and implemented with case study results on the successful engineering design and implementation of new technologies to improve performance and eliminate large nonproductive time events, via the utilization of a successful, repeatable, and operationally safe process.
A thorough evaluation of the CTUDO process was conducted to gain a better understanding of the critical factors that provided the greatest influence on improving performance. The results indicated that the main influencing factors were: wellbore trajectory, plug type, coil tubing size, bottom hole assembly (BHA) selection, fluid rheology QA/QC, real-time modeling, and communication. Rather than instituting and optimizing the critical factors all at once, a piece-by-piece road map was created. Over a five-month trial period, the factors were fully implemented and analyzed. Once the methodology was validated with predictable, repeatable, and successful consistent outcomes, it became the new standard for CTUDO's.
Full implementation of this Factory Model CTUDO methodology has been successfully used for over three years and continues to be the standard process. The well performance impact realized by optimizing the main factors, along with other technological advancements has been substantial. Appropriate engineering design led to better understanding the fluid rheology system and optimal chemical usage and dosage during CTUDO's. Coupled with proper CTU size and BHA optimization, pump rate capability and annular velocity are optimized, while minimizing plug debris size, aided in hole cleaning, which lead to greater efficiency. The use of data analytics to identify trends in downhole tool data, used in conjunction with real-time data allowed for procedure optimization. Operational enhancements include removing planned short trips (ST) and effectively eliminating stuck CTU events. Since the inception of this methodology 320+ horizontal wells ranging from 5,000′ to 10,000′+ have been successfully completed, with well plug counts ranging from 19 to 102. Average time savings is shown to be 66%, and average cost savings 61%. In addition, the process has provided additional cost savings benefits and reduced Put-On-Production (POP) cycle times by eliminating the need of dedicated post drillout flowback.
This paper details the utilization of a simple, effective method for successfully executing and improving performance on CTUDO's. This paper also incorporates lessons learned and best practices from field execution, real-time data analysis and interpretation, and technology implementation. Furthermore, this methodology is designed to be a plug-and-play system, with minimal or no modifications needed to be applied in any unconventional basin across the world.
At reservoir conditions, gas flow confined in submicron pores of shale falls within slip flow and transition flow regimes. Beyond the common instant equilibrium assumption, we believe that gas adsorption/desorption on rough pore surfaces could be in non-equilibrium status when gas pressure keeps decreasing during production. We investigate the interplay of gas slip flow inside complex submicron-scale pores and gas adsorption/desorption kinetics on pore surfaces with computational fluid dynamics (CFD) under unsteady-state flow conditions.
Different from previous studies, the gas adsorption/desorption is in non-equilibrium state, which is closer to real reservoir conditions. Given pore pressure
Any type of adsorption isotherms can be incorporated into our CFD modeling. We investigate the coupling of slip flow and Langmuir adsorption isotherms for methane in 3D reconstructed pore space. We observe that not all of adsorbed gas measured in adsorption isotherms contribute to gas production. In our study the pore pressure,
Gas adsorption/desorption is always regarded as an instant equilibrium process in shale reservoir simulations. This study considers the non-equilibrium gas adsorption/desorption process, which is closer to real reservoir conditions. No studies in the literature have considered the influence of gas adsorption/desorption kinetics when choosing optimum production rates. CFD simulations in this study provide insight and guidelines on optimizing shale gas development with evaluating slip flow as well as gas adsorption/desorption characteristics.
A baseline environmental media monitoring program is presented. Analytical data sets collected by third party contractors at the request of Apache Corporation are presented. The analytical data presented documents the environmental condition of groundwater, surface water, soil, and ambient air, within an area with sensitive environments supporting multiple endangered and threaten species, recently being developed as oil and natural gas exploration and early development. The area of the study is a previously undeveloped portion of the prolific oil and gas development area of the Permian Basin. The baseline environmental media monitoring program occurred over an area of approximately 78 square miles in southern Reeves County, Texas. The analytical data provides interested stakeholders a starting data set for comparison to future environmental conditions, allowing parties to assess if there are changes in the environmental media and if those changes vary from natural seasonal variations.
Process safety approaches developed and implemented over the past 20-30 years have enabled us to improve the design basis of our facilities. Yet we still see major incidents occurring at a steady rate. Traditional approaches to risk management may be appropriate as a basis for design, but they are not helpful in operations management where decisions continuously take place that impacts exposure to Major Accident Hazard (MAH) risk.
A 2017 international survey
The current trend towards digitalization of the industry offers companies an opportunity for a clearer understanding of risk to reduce incidents and enhance the journey towards sustainable production and Operational Excellence. So-called "big data" and "edge data" techniques applied to the streams of data arising from modern facilities holds out the promise of a process safety early warning system that looks at potential signals and trends in facility operations data to make MAH risk exposure visible, prominent and available in real-time.
A new category of Operational Risk Management (ORM) software tools is emerging which seek to deliver on this promise. This paper shares the approaches adopted by two major international oil industry operators who are leveraging a new approach to process safety and operational risk management to achieve safer, more sustainable operations.
The flexural wave imaging technique implemented through an ultrasonic pitch-catch scheme was introduced in the early 2000s to complement the traditional pulse-echo cement evaluation measurements, especially for conditions where the latter fail to provide an unambiguous diagnosis of the annular content. The technique uses separate transmitting and receiving transducers to respectively excite and detect the casing zeroth-order antisymmetric quasi-Lamb mode, also called the flexural mode. A critical attribute of the acquired signals at two receivers is the amplitude attenuation of the early-arriving echo, called the casing arrival, which varies with high enough sensitivity to provide a qualitative measure of the combined effect of the annular content and the bond condition of the cement where cement is in contact with the casing. Specifically, as the cement acoustic impedance increases, the attenuation of the casing arrival amplitude increases up to a certain level and then decreases beyond that. This variation is related to the transition between leakage and nonleakage by the flexural mode of typically a compressional (P) bulk wave into the cement sheath. The estimation of the amplitude attenuation attribute (ATT) is based on the ratio of the peaks of the envelope associated with the analytical signal of the casing arrival across two receivers.
In this contribution, we revisit the physics of the measurement, recognizing that leakage and nonleakage of a bulk wave into the cement sheath are frequency dependent because the phase velocity of the flexural mode is highly dispersive. In particular, for cements with a given bulk-wave velocity,
We demonstrate the workflow first on experimental data acquired with multiple receivers and then on field data acquired with two receivers. A map of the estimated Vcmt shows depth intervals and azimuthal sections where the cement has likely been contaminated with mud to a point that its P wave speed is lowered and crosses the flexural mode dispersion curve to lead to a discontinuity in ATT(f). We discuss ramifications of the quantitative inversion on enhancing the measurement’s diagnosis capabilities.
A robust reservoir surveillance program is the key to successfully managing a steamflood operation. Observation wells allow us to directly monitor changing reservoir conditions throughout the life of the steamflood using time lapse surveys. Temperature surveys are a primary data type collected from the observation wells to evaluate the reservoir heating, and to monitor the steamchest. Thus, accurate measurement and proper interpretation of temperature surveys is essential for steamflood management.
The objective of this study was to look at factors that can impact a temperature log and steps that can be taken to improve temperature measurement accuracy. Several field examples are presented to illustrate the effects of logging speed, steamchest temperature, sensor type and wellbore fluid on recorded temperature data. Guidance on evaluating and interpreting different temperature signatures such as, interpretation of liquid level in an observation well, understanding temperature signatures in air, wellbore reflux phenomenon, and examples of logs from malfunctioning logging tools, are also provided. The main purpose of this work is to aid both the operators and the service companies to gather accurate temperature data for improved steamflood management. This study is based on an extensive study of field data, primarily gathered from a single company's steamflood operations in California (using over 1000 temperature observation wells). Additionally, an analytical model was developed based on reservoir heat transfer and the sensor response mechanism to understand the impact of steam chest temperature, logging speed and sensor response time on the accuracy of the temperature log data. Results from the analytical model support the field observations.
Field data and analytical assessment show that several factors can impact the accuracy of a temperature log, which can subsequently affect our interpretation and operational decisions. Data suggests that higher logging speeds introduce greater error in measured temperature data and these errors are greater at elevated steamchest temperatures. Temperature tools with longer sensor response times need to be run at slower logging speed to get accurate measurements. Ensuring adequate level of thermally equilibrated liquid (typically water) in the observation well is essential both, for gathering accurate data and to mitigate possible safety concerns for the logging operator. The examples and guidelines provided in this study will aid the practitioners to improve the gathering and interpretation of temperature log data.
Flashback 10 years ago to 2008: the North American hydraulic fracturing industry utilized a then record breaking 21.41 Billion pounds and experienced exponential growth year-over-year (excluding 2015 and 2016). Prior to 2008, proppant demand grew at a relatively modest pace and overwhelmingly consisted of 20/40 mesh high quality natural sands and synthetic proppants. Fundamental changes in drilling and completion practices has given rise to a significant increase in the application of smaller mesh proppants, most notably 40/70, 30/50 and various forms of what is generically referred to as 100 mesh sand (i.e., sands that are predominantly smaller than 70 mesh) in natural gas and liquid applications. Proppant demand has now soared, increasing significantly as a result of the new high-intensity completions practices in horizontal wells. In 2018, an estimated 200 Billion pounds will be used for the first time in history (or 10 times that used in 2008).
The proppant supply industry responded well to the increased demand in the past decade, but the industry is increasingly concerned about future supply limitations and the potential impact on completion practices subject to high volume, quality and mesh size availability.
This paper summarizes the historical supply of proppant by type and source, and the driver for each proppant type based on the authors’ current and prior research. The paper will further clarify the basics of proppant by type and size (e.g., what is 100 mesh?) and will address some of the challenges that both the proppant supplier and end-user may face subject to current or desired completion practices. Key observations will be: 1) Potential limitations in the amount of proppant size and type, 2) The impact that specific proppant shortages may have on both supplier and end-user, and 3) Risk factors the proppant supply base may experience subject to future changes in completion design.
The objective of this effort is to encourage the need to study alternative completion designs subject to proppant availability. It is specifically not the intent of this paper to propose one form of completion practice or proppant type over the other.
Making a Difference with Carbon Capture, Utilization and Storage - presented by Nicholas Azzolina