bluuebunny/crossref_metadata_2025 huggingface dataset:
Coalbed Methane Development in China: Challenges and Opportunities
Authors: Carpenter Chris
Published: October 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186289, “Coalbed Methane Development in China: Engineering Challenges and Opportunities,” by Hangyu Li, Shell; Hon Chung Lau, National University of Singapore; and Shan Huang, Shell, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.

For more than a decade, coalbed methane (CBM) has been developed commercially in China, but results have not met expectations. For instance, in 2015, annual CBM production in China totaled less than 5 billion m3 (Bcm) and lagged far behind that of the US (35 Bcm) and Australia (18 Bcm). This paper presents a literature review to determine the engineering challenges and opportunities presented by CBM production in China.

Introduction

China holds the world’s third-largest CBM resources after Russia and Canada. China has multiple basins that contain CBM resources, though the majority of CBM activities are found in the Qinshui and Ordos basins. Together, these two basins contain more than 30% of China’s total CBM resource volume and 93% of discovered geological reserves.

Commercial-scale CBM production in China began in 2004 but did not see a significant increase until 2008. Since then, production has increased approximately threefold but remains significantly lower than that of the US and Australia, as well as the target set by the Chinese government.

China’s lower CBM production is not the result of a smaller development scale compared with those of the US and Australia. In fact, the Qinshui basin alone contains more CBM-producing wells than does the entire state of Queensland. The lower production is, instead, the result of very low single-well gas rates. US and Australian basins have much higher single-well rates than do the Qinshui and Ordos basins. Understanding and identifying additional factors contributing to the unsatisfactory performance of CBM production, however, also is of critical importance.

Coal Characteristics

of the CBM Basins in China Most of China’s CBM development focuses on high-rank (Qinshui) and mid-high-rank (Ordos) coals. It is worth noting that, although there is abundant low-rank coal in the Ordos basin, the large-scale CBM development is found in the eastern part of the basin, where mid- to high-rank coals dominate. The problem with high-rank coals, however, is that they generally have lower permeability than low-rank coals. The highest permeabilities in either the Qinshui or Ordos basins are hardly higher than 10 md, with a large portion less than 0.1 md, while permeabilities in US basins can be 1000 md, with the majority higher than 10 md. Similarly, Australian basins are much more permeable than Chinese basins. The very low coal-seam permeabilities in the Qinshui and Ordos basins suggest that the low single-well gas rate can be attributed largely to low permeability.
Call for More Technology Gains Dominates Unconventionals Conference
Authors: Jacobs Trent , Zborowski Matt , Rassenfoss Stephen
Published: October 2018

In the oil and gas industry, downturns are first met with extreme and widespread pain. But then the industry tends to turn to new technologies, the adoption of which eventually becomes so significant that it changes the makeup of the entire business.

This metamorphic change was on display at the 2018 Unconventional Resources Technology Conference (URTeC) in Houston, where digital technologies and their role in improving economics dominated the discussion. On the exhibition floor and in technical sessions, it was clear that analytics and machine learning tools are enjoying greater uptake and delivering early wins—yet, there remain a number of kinks to work out. Here are some highlights that capture the shale sector’s views on how its digital transformation is shaping up.

 

Pioneer’s Analytics Project Reveals the Good and Bad of Machine Learning

Trent Jacobs, JPT Digital Editor

Machine learning is supposed to help the oil and gas industry discover the important insights that human engineers keep missing. However, a recent project by Pioneer Natural Resources shows that engineers do indeed know their stuff and, while the machines are powerful and full of potential, they still need to get smarter.

 

Big Leaps Still To Come in Unconventional Technology

Matt Zborowski, Technology Writer

Today’s advancements in unconventional technology are worth marveling over, but there is still plenty of room for growth, a panel of industry leaders agreed at the Unconventional Resources Technology Conference (URTeC).

“There are certain times in the history of the industry when technology proceeds at such a fast pace, you would describe it as revolutionary. We are living in one of those times,” said Greg Leveille, ConocoPhillips chief technology officer.

 

In the Shale Business, It’s Time for Another Revolution

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

The report card for unconventional oil and gas producers from a leading industry analyst is A+ for growth and F- for paying back investors.

But Bob Brackett, senior analyst for Sanford C. Bernstein & Co., who created the report card, said he is seeing signs of change.

On the production side, the industry is struggling to keep up with the Permian Basin because output is exceeding available pipeline capacity. On the supply side, the industry may be moving away from pushing production so hard it drives down prices to levels where no one can make money.
Technology Focus: Completions (September 2018)
Authors: Lehr Doug
Published: October 2018

Technology Focus

I am very excited to begin my term as editorial reviewer for Completions. JPT has always been the source of cutting-edge information on industry technology developments, and I pledge to continue that tradition through expert review and selection of papers.

Our industry is showing signs of emerging from the recent downturn, and commodity prices are improving slowly. There is intense focus across the industry on profitability in the current low-oil-price environment, and profitability must be achieved while (a) meeting regulatory requirements, (b) delivering value to stakeholders, and (c) attracting and retaining the best talent available. Yet, today’s profitability is not the only challenge. Laying the groundwork for future profitability also must occur.

One of the more powerful tools available to help achieve sustained profitability is innovation, and it has consistently generated cutting-edge technologies that have advanced the oil and gas industry.

The good news is that innovation has continued during the downturn. For example, advancements in dissolvable-materials technology and downhole data acquisition have continued. While the former primarily advances efficiency in multizone shale well completions, the latter will advance effectiveness in both land and offshore completions. Process innovation is also occurring and is evident in the drive to create advanced numerical models for optimization of stimulation and hardware choices in multizone shale well completions. Finally, increased focus on reliability in design, installation, and operation has emerged as both operators and suppliers recognize the contribution of risk management to completion technology and systems.

The papers presented in this month’s Completions feature are great examples of how innovation is driving profitability, and I hope that they help you drive profitability in your completions.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 188729 Laser Perforation:  Laboratory to Field by Sameeh I. Batarseh, Saudi Aramco, et al.

SPE 187353 Best Practices for Sustained Well Productivity: A Look Back in to Frac-Pack Completions by Mark Knobles, Chevron, et al.

SPE 187185 On/Off ICD Well-Performance Assessment Below an ESP Using Intelligent Chemical Inflow Tracer Technology in a Brownfield in Kuwait by M.A. Siddiqui, KOC, et al.
Technology Focus: Oilfield Chemistry (September 2018)
Authors: Wylde Jonathan
Published: October 2018

Technology Focus

The last 3 years have seen an unprecedented increase in paraffin-related challenges in the world of production chemistry. The industry is producing more-challenging crude oil as the production of light, sweet, and easy-to-treat crude declines. The new crudes coming on stream contain more-complex combinations of paraffinic components.

We are aware of the bimodal distribution of paraffin displayed nicely in high-temperature gas chromatography of, for example, Eagle Ford crude oil, which shows a double peak distribution of paraffin. Some of the more-recent publications highlighted are using more-advanced analytical techniques to characterize crude oil because heavier paraffin components are not detectable by classical methods. Characterization using techniques such as nuclear magnetic resonance and matrix-assisted laser desorption/ionization time-of-flight mass spectrometry are detecting paraffin chains in excess of C100 and determining a trimodal distribution of paraffin in crude oil that is difficult to treat using today’s technology, thus requiring a change in approach and thinking for the production chemist. Such crudes are being developed today—crude oils from some of the more extreme shale plays around the world such as the Montney formation in British Colombia, Canada; Vaca Muerta in Argentina; East African crude oils of Uganda, Chad, and Kenya; and crude oils in the Far East such as those in Indonesia and Vietnam.

The current chemical technology begins to reach its limit of functionality in a crude oil that contains paraffin chains of C75+ in length. The featured papers give some insights into the work under way to elucidate the structure performance relationships between inhibitors and crude oils containing these higher paraffinic species. Much work remains in order to develop more-effective solutions and strategies for these incredibly challenging and highly paraffinic crude oils.

The featured papers summarize some of the state-of-the-art techniques to determine the true nature of paraffin deposition from these bi- and trimodal crude oils as well as advanced techniques to truly characterize and treat produced fluids and recovered solids samples. Readers are encouraged to research the recommended additional reading and take some time to delve into the references contained in these papers. This literature contains an extensive review of the history and current state of the art in paraffin science for the oilfield chemist and engineer.

Recommended additional reading at OnePetro: www.onepetro.org.

OTC 27855 Work Flow To Evaluate Wax-Deposition Risk Along Subsea Production Systems by O. Coronado, Genesis, et al.

OTC 28714 Cold-Finger Benchmarking Study for Paraffin-Inhibitor Selection by Yun Peng, Shell, et al.

SPE 187252 Investigating the Performance of Paraffin Inhibitors Under Different Operating Conditions by Anshul Dubey, The University of Tulsa, et al.
It May Be Boom Time for the Oil-Rich Powder River Basin
Authors: Zborowski Matt
Published: October 2018

Years in the making, the recent steady rise in drilling in the Powder River Basin of northeast Wyoming is generating excitement reminiscent of the early days of currently more-established US onshore oil plays.

The upturn in activity is resulting in double-digit production growth. Wells are bubbling over with oil, and operators are bubbling over with enthusiasm. This has been most evident in recent industry presentations, where decision makers from the basin’s exclusive club of operators have gushed over what is becoming a core asset in their portfolios.

Given the basin’s oil richness, multiple stacked horizons, and well performance and economics, “we think it’s comparable and competitive with the big-name basins—whether it’s the Permian, SCOOP, or STACK,” Joseph DeDominic, president and chief operating officer of Anschutz Exploration, said at a recent SPE Gulf Coast Section meeting on the basin.

“This is what really gets us excited—the fact that you have 5,000 ft of stacked pay which is very similar to what you see in the other basins,” generating a high-dollar amount per acre, said Aaron Ketter, vice president of Devon’s Rockies business unit, during the same event. Formations are “highly economical” at $50/bbl and under, he said, with the heart of the Turner zone sometimes breaking even in the high $30s/bbl.

Traditionally known for its prolific coal production, the Powder River Basin’s potential for oil became a stronger point of focus in the industry about a decade ago. Operators began moving in on the region, rigs in tow, collecting limited but valuable data on its formations. When the commodity price downturn struck the industry during 2014–2016, operators pulled back investment, resulting in the basin’s failure to launch.

In its current state as an oil play, the basin is still underdeveloped. While lots of vertical wells have been drilled there in the past, “the truth is, when you look at horizontal development, and even using modern completions, it’s really brand new. We’re just getting started,” said Joseph A. Mills, Samson Resources II president and chief executive officer. “Delineation is what’s happening today and that’s probably what’s going to go on for another couple of years.”

Companies that are now ahead of the curve arrived early in the basin, secured operatorships, began drilling years ago, held onto their acreage—and its accompanying data—through the downturn, and patiently waited for oil prices to rise and costs to fall.

“What’s unique about the Powder is just the areal extent of some of these zones aren’t the same magnitude as you see in the Permian or the Midcontinent. So zip code really matters,” said Ketter.

Current Lay of the Land

Devon, Anschutz, and EOG Resources have the largest positions in the Powder River at around 400,000 net acres each. Chesapeake Energy and Anadarko Petroleum each has around 300,000 net acres, with the latter firm having just spent some $100 million to expand its position.
Now There’s Enough Pressure Pumping and Sand To Go Around
Authors: Zborowski Matt
Published: October 2018

Operators fracturing wells in the US shale basins are enjoying a steady supply of reasonably priced pressure pumping services and sand.

After the market struggled to keep pace with demand after the downturn, pressure pumpers are deploying enough horsepower to satiate operators and their ambitious production targets, according to data from Rystad Energy. Fracturing work is being augmented by the proliferation of in-basin sand mines, which provide operators a more convenient, less expensive source of proppant during frac jobs.

This comes as the consultancy forecasts the number of horizontal wells fractured to rise 32% in 2018 and 13% in 2019. Total frac stages are projected to increase 37% in 2018 and 16% in 2019. These numbers are based on projected oil prices of around $69/bbl in 2018 and above $70/bbl through 2021.

Demand for pressure pumping horsepower is expected to jump 4 million hp this year to 17 million hp, more than double the 2016 level. Demand is expected to grow 2 million hp in 2019 and another 4 million hp in 2020 to 23 million hp, where it will remain flat in 2021.

On the supply side, horsepower is expected to increase by 4.8 million in 2018, more than meeting demand. Growth will halve to 2.4 million hp in 2019 and then spike to 5.1 million in 2020. The increase next year will primarily serve to fulfill “skyrocketing” demand in the Midcontinent and Haynesville regions, said Ryan Carbrey, Rystad senior vice president, shale research, during a frac market webcast. As of mid-2018, all horsepower that was previously available for refurbishment has been refurbished, Carbrey said, meaning only new horsepower will be added to the field going forward. The overall increased supply—from both refurbished units and newbuilds—has stabilized the market, and price increases aren’t expected through late 2018 or early 2019.

However, some operators aren’t pleased with the work they’re seeing, Rystad has observed. A vice president of one exploration and production (E&P) firm told the consultancy, “Some of these companies grew too fast and the quality of their crews reflect that—too many new guys that don’t know what they’re doing yet.”

Meanwhile, pumping intensity growth, which has increased rapidly since the downturn, is forecast to decline in the coming years “as we believe a lot of the gains from increasing horsepower hours have already been realized,” said Carbrey.

A measure of that intensity, horsepower-hours per horizontal well, are expected to increase by an average of just 2% per year between 2017 and 2021 after an average 29% per year between 2013 and 2017.
Data-Analytics Method Helps Engineers Optimize Well Placement Under Uncertainty
Authors: Wilson Adam
Published: October 2018

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 188265, “Use of Data Analytics To Improve Well-Placement Optimization Under Uncertainty,” by Daniel Busby, SPE, Frédérik Pivot, and Amine Tadjer, Total, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.

Well-placement optimization is one of the more challenging problems in the oil and gas industry. Although several optimization methods have been proposed, the most-used approach remains that of manual optimization by reservoir engineers. The work flow proposed here uses a machine-learning algorithm trained on simulated data to evaluate the performance of possible well locations and configurations.

Introduction

Extensive literature has been published about well-placement optimization; authors have proposed many different approaches (e.g., advanced optimization techniques, adjoint methods, experimental design, and streamline solutions). Real field experience, however, has shown that these techniques are rarely used. In practice, expert engineers usually identify the main factors affecting a future well’s production. They consider these factors in obtaining the best well configurations. These are then evaluated with a full-field reservoir-simulation model. Uncertainty is handled in the process typically in a second phase to test the robustness of the proposed development plan by running a few alternative models corresponding to some low and high cases and, more rarely, on a full Monte Carlo set of models generated by the full prior-model uncertainty.

The reasons the different optimization methods proposed in the literature are not used in operations can vary: difficulty in handling all the operational constraints during optimization, a prohibitive number of simulation runs, relatively poor performance of the optimization methods when considering many complex production and injection wells, and the complexity of the method and its configuration. The approach proposed here is not a proper well-placement optimization method; it is more a set of data-analytics tools aimed at helping reservoir engineers to explore the extremely large domain of possible solutions and, it is hoped, to find better solutions. This paper’s objective is to provide a methodology and some guidelines that can be adapted to each specific field case. The idea is to follow the typical work flow used by reservoir engineers while adding data-analytics techniques to improve the decision-making process.

Methodology

This work presents a methodology to address the problem of field development planning mainly for greenfields, although a similar work flow can be applied to mature fields. The first step in field development planning is to perform a study to incorporate geological, seismic, and fluid data into a reservoir-simulation model.
Solvent-Based and Solvent-Assisted Recovery Processes: State of the Art
Authors: Bayestehparvin Bita , Farouq Ali S. M. , Abedi Jalal
Published: October 2018

Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).

The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.
A Mass-Conservative Sequential Implicit Multiscale Method for Isothermal Equation-of-State Compositional Problems
Authors: Møyner Olav , Tchelepi Hamdi A.
Published: October 2018

Compositional simulation is necessary for a wide variety of reservoir-simulation applications, and it is especially valuable for accurate modeling of near-miscible gas injection for enhanced oil recovery. Because the nonlinear behavior of gas injection is sensitive to the resolution of the simulation grid used, it is important to use a fine grid to accurately resolve the compositional and saturation gradients. Compositional simulation of highly detailed reservoir models entails the use of small timesteps and large, poorly conditioned linear systems. The high computational cost of solving such systems renders field-scale simulations practically unfeasible. The coupling of the flow and transport to the phase-equilibrium calculations adds to the challenge. This is especially the case for near-miscible gas injection, in which the phase state and the phase compositions are very strong functions of space and time.

We present a multiscale solver for compositional displacements with three-phase fluid flow. The thermodynamic phase behavior is described by general nonlinear cubic equations of state (EOS). The fully implicit (FI) natural-variables formulation is used as the basis to derive a sequential implicit (SI) solution strategy, whereby the pressure field is decoupled from the multicomponent transport. The SI scheme is mass conservative without the need to iterate between the pressure and transport equations during the timestep. This conservation property allows the errors caused by fixing the total-velocity field between the pressure- and transport-updating steps to be represented as a volume error. The method computes approximate pressure solutions—within a prescribed residual tolerance—that yield conservative fluxes on the computational grid of interest (fine, coarse, or intermediate). We use basis functions computed using restricted smoothing to allow for generally unstructured grids.

The new method is verified against existing research and commercial compositional simulators using a simple conceptual test case and also using more-complex cases represented on both unstructured and corner-point grids with strong heterogeneity, faults, and pinched-out and eroded cells.

The SI method and the implementation described here represent the first demonstrated multiscale method applicable to general compositional problems with complexity relevant for industrial-reservoir simulation.
Automatic Flare-Stack Monitoring
Authors: Janssen R.. , Sepasian N..
Published: October 2018

Flare stacks must be monitored continuously to ensure ignition of released gases during the plant operation. Generally, the process of flare detection refers to detecting the presence or absence of a flare. Flare monitoring adds the capability of tracking the size of the flare to this process. By setting lower and upper monitoring boundaries, an alarm can be generated if the flare becomes too small or too big. Reliable flare-stack monitoring becomes crucial to ensure that no unburned toxic or waste gas is released into the atmosphere, causing environmental issues and possible fire hazards. It also gives the operator an extra handle to optimize the production process. In this paper, we introduce an automatic flare-detection and monitoring system. Our user-friendly system is computer-vision-based, plug-and-play, and designed as a built-in part of the camera. By taking advantage of the geometrical properties of the flare as well as temporal information obtained by video analytics, we create a monitoring system that is robust to various parameters such as wind direction. To the best of our knowledge, we are the first to present an automatic flare-stack-monitoring system with flare-size tracking and automatic event signaling. Our presented system has been tested for live monitoring in the Rotterdam Botlek area, The Netherlands. The preliminary results illustrate a reliable system that is free of false alarms.
Construction of a 3D Geomechanical Model for Development of a Shale Gas Reservoir in the Sichuan Basin
Authors: Xie Jun , Qiu Kaibin , Zhong Bing , Pan Yuanwei , Shi Xuewen , Wang Lizhi
Published: October 2018

Currently, there is large-scale shale gas exploration and development in the Sichuan Basin, western China. Caused by high tectonic stress and presence of fracture systems at various scales in the lower Silurian Longmaxi reservoir formation, hydraulic fracturing in shale gas reservoirs in the Sichuan Basin has encountered many difficulties, such as placing sufficient proppant, poor-production performance for some wells, and ambiguity as to the factors controlling the production of reservoirs. It has been recognized that lack of geomechanical understanding of the shale gas reservoirs is a major obstacle to effectively addressing these difficulties.

A 3D full-field geomechanics model was constructed for the Changning shale gas reservoir in the Sichuan Basin through integrating seismic, geological structure, log, and core data by following a newly formulated work flow. The 3D geomechanical model includes 3D anisotropic mechanical properties, 3D pore pressure, and the 3D in-situ stress field. Through leveraging measurements from an advanced sonic tool and core data, the anisotropy of the formation was captured at wellbores and propagated to 3D space guided by prestack seismic inversion data. The 3D pore-pressure prediction was conducted with seismic data, and calibrated against pressure measurements, mud-logging data, and flowback data. A discrete-fracture-network (DFN) model, which represents multiscale natural-fracture systems, was integrated into the 3D geomechanical model during stress modeling to reflect the disturbance on the in-situ stress field by the presence of the natural-fracture systems.

The 3D pore-pressure model was used to calculate more-reliable estimates of gas in place in the shale gas reservoir, and the geomechanical model was used to reveal the root cause of difficulties of proppant placement in this tectonically active and unevenly fractured shale gas reservoir.

The paper presents the highlights and innovations in constructing the 3D geomechanical model for the shale gas reservoir, and explains how the 3D geomechanical model is used to address technical challenges encountered during drilling and completion. Also, it demonstrates that a reliable 3D geomechanical model, with proper characterization of anisotropy, pore pressure, and natural fractures, provides a critical opportunity to improve the development in this shale gas reservoir.
A Mechanistic Model to Predict Flow Pattern Transitions in Electrical Submersible Pump under Gassy Flow Condition
Authors: Zhu Jianjun , Zhang Jiecheng , Zhu Haiwen , Zhang Hong-Quan
Published: October 2018

Gas entrainment is frequently encountered in electrical submersible pump (ESP) as an artificial lift method for oil production. When this occurs, ESP suffers from moderate to serve performance degradation depending on inlet gas volumetric fraction (GVF). The resulted pressure surging may cause vibrations and short run-life of ESPs. For better design of ESP system, a mechanistic model is needed to accurately predict its performance with gas-liquid flow. Similar to modeling multiphase pipe flow, the flow pattern identification and classification inside a rotating ESP is thus of great importance. In this paper, we propose a new mechanistic model to map flow patterns in ESP operated under gassy flow conditions. The model is validated by comparing to experimental results with good agreement.

The experimental facility for testing ESP two-phase performance was designed and constructed. The main flow loop comprises a 3" stainless steel liquid flow loop and V" gas flow loop. A radial-type ESP with 14 stages assembled in series is horizontally mounted on a testing bench. Pressure ports were drilled at each stage to measure stage-by-stage pump pressure increment. The mixture of gas and liquid is separated in a horizontal separator, where excessive air is vented and liquid continues circulation. Experimental data are acquired with two types of tests (mapping and surging tests) to completely evaluate the pump behaviors at different operational conditions. The water/gas flow rates, ESP rotational speeds, intake pressure and surfactant concentrations are controlled in the experiments.

For two-phase flow, ESP pressure increment suffers from more severe degradation as gas flow rate increases. With the performance curves obtained in surging or mapping tests, ESP flow patterns including dispersed bubble flow, bubbly flow, intermittent flow and segregated flow can be identified. The pattern transition boundaries are mapped. Starting from the free body diagram on a stable single bubble, the transition boundaries of dispersed bubble flow to bubbly flow and bubbly flow to intermittent flow are formulated. Based on the combined momentum equation, the transition criterion of intermittent flow to segregated flow is derived. The flow pattern map calculated from the new mechanistic model agrees well with that detected from ESP performance curves.
Evaluating Tailpipe Systems Designed to Optimize Artificial Lift Performance in Horizontal Wells
Authors: Humphreys C. R. , Vangolen B. N. , Allison A. P. , Yin D.. , Yicon C..
Published: October 2018

Objectives/Scope

The performance of artificial lift systems on horizontal wells is greatly influenced by both the volume of gas produced and the tendency for gas slugging. With a sucker rod pump (SRP) system, this behaviour leads to gas interference at the pump, reducing system efficiency and equipment run life. With an electric submersible pump (ESP), gas slugs can cause cycling of the ESP, which may significantly shorten its run life. A trial project was launched to evaluate the performance of two tailpipe systems that could be applied to both forms of artificial lift to achieve the following goals:

Methods, Procedures, Process

Two tailpipe systems were tested in a number of wells using both SRPs and one ESP for lift. The systems differ in both separator design and packer location. The first uses a conventional packer-style gas separator with a reduced inner diameter (ID) tailpipe extending below the separator and past the KOP. The second uses a specialty cyclonic separator with a reduced ID tailpipe, and the packer is located at the lower end of the tailpipe.

Some of these installations are outfitted with downhole gauges (DHGs) measuring pressure and temperature at several points along the tailpipe. The DHGs recorded pressure at the tailpipe inlet, tailpipe outlet, pump intake pressure, and pump discharge pressure. This surveillance package allowed for real-time monitoring of the performance of both the tailpipe and the artificial lift system, while also providing data for modelling the flow regime through the tailpipe. The modelling results were used to forecast long-term performance of the system as the well production declines over time.

Results, Observations, Conclusions

Results from the field trial show the performance of each system from a variety of standpoints: changes in flowing bottomhole pressure, flowing behaviour through the tailpipe, separation effectiveness, and changes in production. Challenges were noted, and potential solutions or courses of investigation are proposed. Conclusions were drawn regarding the overall effectiveness of the concept, as well as the relative effectiveness of the two systems.

Novel/Additive Information

We examined the differences between two tailpipe systems regarding the isolation location, whether at the top or bottom of the tailpipe, to aid us in designing future systems. A comparison of the two separators was attempted, and various operational challenges are discussed so as to improve the design, installation, startup, and operation of these systems.
Unconventional Lift for Unconventional Wells
Authors: Bill Jackson W. J.
Published: October 2018

At some point during production, all wells experience a drop-in reservoir pressure that hinders production. This requires an artificial lift system to reduce the hydrostatic pressure on the formation, in order to encourage more production to the surface. Selecting the proper artificial lift method is critical to the performance and profitability of today's unconventional wells. This presentation will examine the range of artificial lift solutions available for horizontal and multi-stage wells and discuss the advantages of hydraulic jet pumps versus rod pumps, electronic submersible pumps, and gas lift systems. A review of typical producing Permian Basin, Eagle Ford, and East Texas sites will show the efficiency, versatility and reliability of hydraulic jet pumps can provide unmatched advantages when addressing the artificial lift challenges presented by unconventional, horizontal, multi-stage wells.
Cultural Change in ALS Real Time Operation and Optimization in Vaca Muerta Through CWE
Authors: Claramunt J. I. , Bizzotto P. E. , Sapag F.. , Ferrigno E.. , Barros J. L. , Martinez G..
Published: October 2018

The present work summarizes the experiences and lessons learned around the deployment of the first Collaborative Work Environment (CWE) at the Loma Campana field, producer of the Unconventional formation Vaca Muerta in YPF SA, Argentina.

In the context of the development of the first Unconventional field in Argentina, it was decided to telesupervise and automate all the facilities and wells. It was decided to create a centralized decision support centre (DSC) to manage the entire field operation, and to optimize the production in real time.

Despite the technological capabilities of the telesupervision tools, there was an opportunity to improve online diagnosis and the process of decision-making for well optimization based on real-time information and data from the field.

This opportunity was the starter for the creation of the first CWE in YPF Upstrem operations, to unify and coordinate online actions detected between production supervisros, DSC Supervisors, production and reservoir engineers.
Effective Approach to Wellbore Clean Out Operation: A Case Study from Zawtika Phase 1B
Authors: Choodesh Attawit , Rutland Marvin Gary , Graham Grant Colin William
Published: October 2018

Free sand movement and fines mobilization during production in Zawtika field is one of the main challenges and can result in failures of production systems leading to SSHE exposure, loss of production or even well suspended. The optimum completion design Cased Hole Gravel Pack (CHGP) allows the well to maintain solid-free gas production with (limiting skin) selectivity, longevity and integrity throughout the life cycle.

The Sand Control completion deployment, effectiveness and well productivity is directly related to the cleanliness of cased well bore and completion brine. The Total Solid Suspension (TSS) and Nephelometric Turbidity Units (NTU) or clarity of the fluid is the key indicator of well cleanliness. Zawtika Phase 1A post job review highlighted that Wellbore Cleanout (WBCO) is one of the most time consuming operation. To overcome this challenge and create areas of opportunities for improvement based on efficiencies, several possible solutions identified below.

Excessive pipe dope, metal debris and rust from casing can collect within the well bore, bridge in perforation tunnels and ultimately damage reservoir or seriously hinder running completion components. The correct combination of Pipe Dope applying procedure, Chemical Displacement, Mechanical Movement and Hydraulic Displacement are the main key contributing factors to improved operation safety, deployment operational efficiency. Lab scale test conducted to simulate test for pipe dope removal chemical, Mechanical Casing Scraper and casing brush simulate testing in order to remove casing vanishing coating, also applying wellbore cleaning concept from drilling - rotational, pump rate and trip speed

Recovery of metal or other debris in a limited number of runs gives several advantages: - Minimize reservoir damage - Reduces risks of screen plugging - Saves rig time. This paper will describe planning process, pipe dope procedure, wellbore clean out chemical / mechanical tool selection based on laboratory testing, displacement techniques, and operation summary. The potential cost saving to project can be more than 5 Million USD. The combination of this improvement in WBCO operation is able to reduce the operation time and cost in Phase 1B more than 71% comparing to Phase 1A performances in 2014-2015
Successful UBD Application through the Full Operation Cycle of the Production Section on an Exploration Gas Well in Thailand: A Case History
Authors: Wang Ping
Published: October 2018

Major challenges faced by today's industry in drilling fractured carbonate reservoirs are formation damage and potential drilling problems such as fluid loss and differential sticking. To drill such formations, underbalanced drilling (UBD) technology has been used as it can intentionally keep the bottomhole pressure (BHP) lower than the pore pressure (PP), which will eliminate the near-wellbore damage, and mitigate drilling problems like fluid losses. This technology was also used onshore in Thailand, mostly for development wells with low-pressure reservoirs. Well-A, located in the fractured carbonate Pha Nok Khao (PNK) formation of northeast Thailand is an exploration well with expected reservoir pressure around 6,000 psi (13 ppg in equivalent density), whose operator was determined to utilize UBD for the production section in order to minimize formation damage and maximize and test productivity.

The higher reservoir pressure leads to higher operational risks for UBD. While drilling, single-phase water based mud (WBM) was used to keep proper drawdown for this section. In order to have safe and efficient tripping operations, tandem downhole deployment valves (DDV) were utilized to provide ultra-reliable isolation of the wellbore for all the trips during drilling, logging and completion, which eliminated the need to snub or kill the well—any of which would lead to potential formation damage and safety issues. After completion, isochronal well testing was conducted using the same UBD package and later, in order to obtain more data to determine whether the operator could commercially develop the field. After that, a long-term well-test operation was conducted by continuously flaring the well at variable rates for 15 days using the same package.

As the well was in an underbalanced condition through all the operation phases, no formation damage, fluid losses and NPT happened during the whole operation. The use of same UBD package from drilling till well testing for the full operation cycle also minimized costs and rig time.

This paper details the UBD approaches used to minimize formation damage and evaluate reservoir productivity for the Well-A in the PNK formation of northeast Thailand.
Non-Portland Cement Slurry Development and Application for Ultrahigh-Temperature Geothermal Well with Supercritical Conditions
Authors: Martino Guido Di , Ruch Andreas
Published: October 2018

Exploring supercritical fluids and investigations of their characteristics for geothermal use requires risk minimization similar to those in oil and gas applications. The geothermal operating company leading the DESCRAMBLE (DESCRAMBLE 2018) project consortium within the European Union's (EU) research and innovation programme Horizon 2020, requested a tailored cement slurry suitable as a dependable long-term barrier and appropriate cementing practices which suit the targeted K-horizon's expected supercritical conditions.

A scouting study was performed testing two different Portland-cement silica flour blends under targeted conditions. Additionally, a blend comprising calcium aluminate phosphate cement was selected for this test series. Non-Portland slurry designs have been used in high-temperature geothermal wells (Berard, 2009) as well as in steam injection applications (Li, 2016).

Because of testing equipment limitations, samples were cured at 200°C/206 bar and then heated to 450°C at ambient pressure during the scouting phase. The non-Portland design proved to be the best candidate, although all three cement designs showed cracking. As a result, it was decided to further improve the non-Portland cement's mechanical properties by adding modifiers that would not affect the high-temperature rating of the cement. During the second phase, it was also necessary to consider the operational side of slurry design, as placement temperature was 200 °C with a requirement of more than 5 hours thickening time, which is near the upper limit for a non-Portland cement blend. Additionally, testing conditions were ramped up close to supercritical conditions during initial curing, and samples then underwent further curing at 550 °C and ambient pressure. Tri-axial mechanical properties were evaluated after cooldown.

From an operational aspect, it became apparent during lab testing that mixing order was important as well as extended temperature simulation to help ensure the well was properly cooled down before cement placement. Once all laboratory testing, simulations, and operational preparations were complete the actual 7-inch liner cementing operation was performed with the desired results. Use of a specially modified calcium aluminate phosphate cement blend was successful and initial results from the well showed that this cement system was properly tailored to the geothermal well conditions.

Only a few geothermal wells have been attempted previously under such conditions, hence it was necessary to create and deliver a modified cement slurry design for both geothermal and oil and gas applications. Further monitoring of the cement sheath will be conducted to evaluate long-term properties.
A Sustainable Approach to Production Increase in the Zawtika Field: Sand Control Assisted with Hydrofluoric Acidizing
Authors: William Colin , Grant Graham , Choodesh Attawit , Ramirez Cristian , Nusyirwan Ahmad , Santoso Doffie Cahyanto
Published: October 2018

Sand and fines production in oil and gas wells are a major challenge that can result in production system failures. In unconsolidated sand reservoirs, proper sand-control practices are necessary to help prevent reservoir sand production. To remove formation damage and control fines migration, acid treatments are pumped ahead of sand-control treatments, which can be challenging because variations in mineralogy determine fluid performance and require a customized fluid selection. For this case, improvements in cased hole sand-control completions were initially sought by switching to high-rate water pack (HRWP) or fracture for placement of gravel (FPG) techniques; however, obtaining fracture conductivity and minimizing out-of-zone fracture growth was challenging. To accomplish the latter, fluid selection was optimized with linear-gel systems and relative permeability modifiers as prepad systems. Operators should know the formation's composition at the treatment point for a successful acidizing treatment to be performed. The dominant mineral component and temperature of the target formation determines the most effective preflush, hydrofluoric (HF)/hydrochloric (HCl) acid treatment blend, and preflush/treatment volume.

The successful implementation of HRWP and FPG techniques produced excellent results with regards to skin minimization and production maximization. The HRWP technique was applied when gas/water contact was nearby, allowing flow from a moderate to high payzone kh (permeability × net pay), and FPG was used to produce a proper flow in low kh formations.

The goal of sandstone-matrix acidizing is to remove siliceous microparticles blocking or bridging pore throats by injecting acid formulations containing HF acid. The presence of potassium feldspars, sodium feldspars, illite, and zeolites is a concern because these compounds can form or contribute to forming significant matrix-blocking precipitates, such as sodium or potassium fluosilicates and aluminum fluorides, during HF/HCl treatments. Variations in mineralogy determine fluid performance and make customized fluid selection necessary. The goal is to minimize the risk of over acidizing the near-wellbore region and to extend the reaction for deeper penetration when possible. In some cases, the acid systems with the equivalent strength of up to 1.5% HF acid were used.

This paper describes the planning process, acid treatment selection based on laboratory testing, placement and diversion techniques, sand-control completions selection, operation summary, and evaluation of treatment success.
Using Simultaneous Gyro Measurements to Determine Orientation of Magnetic Ranging Instruments in a Vertical Environment
Authors: Rassadkin G. , Ridgway D. , Moss C. J.
Published: October 2018

A variety of magnetic ranging methods are used to determine distance and direction between a magnetic field sensor and a magnetic field source. If the sensor is in a near vertical hole, it may be difficult to orient the sensor's axes relative to known world coordinates, since no gravity high side is available. This can create difficulties calculating and applying ranging results. A magnetic azimuthal toolface may also be impaired due to magnetic interference.

To address this problem, we combine and align ranging and gyro systems in one tool-string and use simultaneous gyro attitude measurements to define the orientation of a ranging system with respect to True North. We apply this technique to two distinct magnetic ranging methods. The first method consists of a solenoid based ranging system. The example shows how this method was used to drill a precisely parallel wellbore in a close proximity to a previously drilled vertical well. The second described method consists of an at-bit-while-drilling ranging system that was used to safely pass by a vertical well while drilling a horizontal well in a close proximity.

The paper compares the results of alternative north orientation techniques for magnetic ranging versus the simultaneous gyro attitude referencing. The alternative techniques include a magnetic north orientation and the north orientation derived from a prior downhole survey and gravity high side tool face. The results show that the described technique can improve magnetic ranging accuracy by up to 10-fold over the previous methods. The paper provides 2D and 3D visualization and numerical analysis of the listed north orientation techniques applied to the magnetic ranging methods.

Simultaneous gyro measurements can significantly improve magnetic ranging accuracy. The applications for the described technique include relief well drilling, plug and abandonment, collision avoidance/risk mitigation, civil and mining projects.