bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Drilling Systems Automation and Management (September 2018)
Authors: Macpherson John
Published: October 2018

Technology Focus

Signs of maturity in drilling systems automation are evident in the success stories filtering out of technical conferences and in the attraction of top university talent to an annual, international, drilling-systems-automation contest.

This international university competition is focused on designing an automated (push-the-button) drilling rig. It is sponsored by the SPE Drilling Systems Automation Technical Section and is referred to as Drillbotics (www.drillbotics.org). It is not only about automating equipment, however. The system must drill a quality hole in a block of unknown composition. The competition has raised aware-ness of drilling systems automation in academia and now shares space with an elite group of university competitions, among them Shell’s Eco-marathon and SpaceX’s Hyperloop.

Drilling-systems-automation products are now being released commercially. These are primarily focused on drilling optimization and wellbore positioning. Several approaches are being considered for the latter—automated placement of the wellbore in 3D space—including auto-mated slide drilling and automated use of rotary steerables. The benefit of these systems is becoming obvious as demanned and even unmanned directional-drilling operations are starting to take hold in the US land environment.

A couple of upcoming drilling-systems-automation sessions are of interest. The first is at the SPE Annual Technical Conference and Exhibition, 24–26 September, in Dallas addressing “The Automation of Well Placement.” The focus is on the successful integration of multiple technologies to allow the next steps in automated directional drilling: geosteering and reservoir navigation. The second is a session on the “Digital Twin for Drilling” at the SPE/IADC Drilling Conference and Exhibition, 5–7 March 2019, in The Hague. As described by the conference, “a digital twin integrates real-time data with both physics-based and data-driven models of a physical asset to create a dynamic understanding and optimization of its design, operation, performance, and maintenance.”

As you can see, significant progress is occurring in drilling systems automation, and I hope you can participate in both sessions guiding systems automation for drilling and as a Drillbotics volunteer guiding the talent for the future of the industry.

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

IADC/SPE 189653 Reducing Stick/Slip by Avoiding Autodriller-Control Dysfunction by Derek Adam, Occidental, et al.

IADC/SPE 189691 Automated Directional Drilling Software and Remote Operations Centers Drive Rig Fleet Well Delivery Improvement by Colin Gillan, Nabors Industries, et al.

SPE 187447 Challenges and Lessons From Implementing a Real-Time Drilling Advisory System by Benjamin J. Spivey, ExxonMobil, et al.
New Geosteering Work Flow Integrates Real-Time Measurements With Geomodels
Authors: Wilson Adam
Published: October 2018

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191337, “An Interactive Decision Support System for Geosteering Operations,” by Sergey Alyaev, IRIS; Reidar Brumer Bratvold, SPE, University of Stavanger; and Xiaodong Luo, SPE, Erich Suter, SPE, and Erlend H. Vefring, SPE, IRIS, prepared for the 2018 SPE Norway One Day Seminar, Bergen, Norway, 18 April. The paper has not been peer reviewed.

To place a well in the best possible reservoir zone, operators use geosteering to support real-time well-trajectory adjustments. Geosteering refers to the process of making directional well adjustments on the basis of real-time information acquired while drilling. This work presents a systematic geosteering work flow that automatically integrates a priori information and real-time measurements to update geomodels with uncertainties and uses the latest model predictions in a decision-support system (DSS). The DSS supports geosteering decisions by evaluating production potential against drilling and completion risks.

Introduction

This paper presents a consistent, systematic, and transparent work flow for geosteering. The starting point is a priori information, for example a probabilistic geomodel representing a geological interpretation based on surface seismic and logs from offset wells, including relevant interpretation uncertainties. Multiple geomodel realizations of the possible geological scenarios span the space of interpretation uncertainties. The real-time measurements obtained while drilling are continually integrated by updating the realizations automatically using an ensemble-based filtering method. The real-time update of the realizations leads to a reduction in interpretation uncertainty, providing up-to-date predictions of the geology ahead of the bit consistently. The update work flow is linked to a DSS. The DSS applies the probabilistic up-to-date geomodel to support geosteering decisions under uncertainty by evaluating the chosen value function of the well. The value function commonly includes multiple objectives, including production potential, costs for drilling and completion, and risks associated with the operation. The DSS presented here is optimized specifically for use with ensemble-based update work flows that are increasingly popular in the oil industry.

The focus of this paper is the DSS. The DSS suggests steering correction or stopping, optimizing well trajectories over the ensemble of up-to-date geomodel realizations. A graphical user interface (GUI) enables geosteering experts to control the input to the DSS by means of interactive selection and adjustment of value functions and constraints (e.g., dogleg severity). The adjustments are applied in a matter of seconds using advanced dynamic programming algorithms that yield consistently updated decisions. The proposed steering decision is communicated through the GUI, which contains a visual representation of the current uncertainty and trajectory possibilities that give the best value for each realization.
BP and Startup Beyond Limits Try To Prove That Cognitive AI Is Ready for Oil and Gas
Authors: Jacobs Trent
Published: October 2018

BP has invested more than $100 million into nine different startup companies in the past 2 years—but only one of them wants to turn your brain into a piece of its software.

The international major is working with the ambitiously named firm Beyond Limits on a set of artificial intelligence (AI) programs that will absorb the learnings of geologists and petroleum engineers, and then imitate their decision-making processes as they work on subsurface challenges together.

Before this partnership, Beyond Limits had never been involved in solving the complexities of oil and gas, which is something that might be counted against it by venture capital or prospective upstream clients. But after BP saw what the young company was working with in its office about 10 miles north of downtown Los Angeles, it decided to become both its largest client and its largest investor by injecting it with $20 million a year ago.

The attraction for BP came down to getting its hands on a strain of AI known as cognitive computing, or what Paul Stone refers to as “the pinnacle of the artificial intelligence pyramid.”

“We haven’t seen that elsewhere, so we wanted to be the first to engage and see where it might go in the oil and gas industry,” said Stone, who serves as a technology director in BP’s digital innovation group.

And where it lacks a prior track record in oil and gas, Beyond Limits compensates with a technology team that helped design most of the same intelligent software it is licensing from the Jet Propulsion Laboratory ( JPL), an institution run by the influential California Institute of Technology in cooperation with NASA. Similar to oil and gas explorers, at JPL immense uncertainty is the perpetual driver for emerging technologies.

AJ Abdallat has served as chief executive officer of Beyond Limits since its founding in 2014 and previously spear-headed several other startups that have been spun out of work first done at JPL. He believes that this firm’s pedigree gives it a big head start in pushing the envelope on cognitive computing because “the issues and challenges we are tackling today, JPL has been tackling for decades.”

And though there remains a lively debate about where cognitive computing really stands today in terms of its human-like reasoning capabilities, Abdallat said, “People tend to judge AI based on the last 2 or 3 decades—you really need to look at what has happened in the past 5 to 6 years.”

Some of the most notable recent advancements include the AI sector proving that intelligent programs can best human reasoning when it comes to complex games such as Go and Texas Hold’em Poker. Cognitive programs also demonstrate growing promise as a diagnostic tool in the healthcare industry—a vertical that Beyond Limits is positioning itself to break into along with oil and gas.
Shell, Bluware Team Up on Seismic With Video Game Tech
Authors: Jacobs Trent
Published: October 2018

Looking for oil and gas is becoming a lot more like a video game.

This is the unique intersection where Houston-based Bluware stands. The software company is among a handful of first movers in the upstream industry that see the use of GPUs, or graphics processing units, as the way to eliminate all the wasted time spent waiting for seismic data to be visualized.

GPUs have been around for decades, but only in the past few years have they become one of the most talked-about pieces of computing hardware in the digital tech scene.

Their uptake was initially driven by the need to quickly render graphically rich video games, especially first-person shooters, and enable players sitting around the world to co-play online without lag. Others have since awoken to the potential of GPU technology, which is now accelerating the development of driverless cars and represents the computing muscle behind cryptocurrency markets.

In the modern video game setting, any significant latency in processing might mean game over. “Whereas in oil and gas, if you have to wait another half an hour to get a seismic line to load, you just go get a cup of coffee,” Bluware Chief Executive Officer Dan Piette said.

If that time is given back, those coffee breaks may be the thing put on hold as seismic processing ceases to be a major bottleneck. Bluware says on its website that it can shave several months off the typical seismic project.

Piette said this could translate into operators gaining the inside track on bidding for offshore blocks that their competitors might bypass simply because of using slower interpretation methods that rely on traditional hardware.

More Seismic, Fewer Eyeballs

And even though the industry downturn hit offshore exploration budgets as hard as any other part of the service business, Bluware sees plenty of opportunities for its cloud platform that also incorporates machine-learning tools to help automate key parts of subsurface characterization workflows.

The company estimates that global producers are sitting on at least 1.5 exabytes of seismic data sets that can be reprocessed with modern technology to find more oil and gas. To put the volume of this data into perspective, an exabyte is equal to more than 1,000 petabytes while a high-resolution offshore survey in the Gulf of Mexico might sail home with between 1–2 petabytes.

Piette argues that this inventory of data is only getting bigger in size, and that the lasting effects of the down-turn mean there are not enough technical professionals to interpret it all. “You can’t have 50 geophysicists looking at one petabyte of data and come up with the answer anymore—you need one geophysicist looking at 50 petabytes of data,” he said.
Technology Focus: Field Development Projects (October 2018)
Authors: Capello Maria A.
Published: October 2018

Technology Focus

Maximizing recovery and production used to be the main goal of field development plans, but that may be in the past. Extended periods of low oil prices and the incumbent use of data-driven work flows have triggered changes in the development of field development plans toward maximizing economic margins.

Recent advances in field development are not based on specific technical breakthroughs (although shale oil and gas and deep oil owe a lot to those) but on economic models and scenarios run at the very beginning, before any dollar is invested. This is true for companies large or small, public or private, and for national oil companies.

Major SPE conferences in 2017 and 2018 were hubs for numerous technical papers that portray the new trends in field development, such as basing decisions on the analysis of economic models and profitability elements. Certainly, operating companies are migrating from complex, lengthy, and bureaucratic approaches to capital-expenditure (CAPEX) decisions and approvals for field development plans to more data-driven decisions based on economic analysis using new tools.

Artificial intelligence, supervised/ guided machine learning, and massive and advanced data analytics play fundamental roles in the preparation of new field development plans, where well, field, and facilities information is shaped into high-resolution models that consider the micro and the macro elements. What previously was considered luxurious, such as high-resolution 3D seismic data and digital technologies, has become fundamental. Focusing on the maximization of margins using data-driven work flows enables better decisions at the field development stage and has yielded dramatic CAPEX/operational-expenditure optimizations and reductions, shrinking the time to first oil and triggering approvals of plans quicker.

I am confident you will enjoy reading these articles outlining the new trends in field development. The industry is evolving toward a data-driven approach to profitability, and we need to catch the wave.

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

OTC 28791 Optimized Field Development Through Integrating Field Network With Dynamic Reservoir Model by Mahanaz Hatvik, TechnipFMC, et al.

SPE 190239 Machine-Learning-Based Optimization of Well Locations and WAG Parameters Under Geologic Uncertainty by Azor Nwachukwu, The University of Texas at Austin, et al.

OTC 28970 A Universal Field Development Approach for Advancing Stalled GOM Deepwater Projects by Richard D’Souza, Granherne, et al.
Technology Focus: New-Frontier Reservoirs II (October 2018)
Authors: Kalfayan Leonard
Published: October 2018

Technology Focus

With the recent increase in new-well activity in unconventional reservoirs and the well-factory approach, a natural limitation exists in the capacity for implementing hydraulic-fracturing optimization. An even greater limitation exists with the consideration of stimulating production from existing wells in decline. Great strides have been made in drilling and completion efficiencies and well-cost reduction during the past several years. That focus has been most important in the lower-for-longer oil-price environment we have fought through.

Naturally, that focus has, to some extent, limited alteration of initial-stimulation design—for example, with respect to fracture-stage sizes, fracture-spacing optimization, and proppant types and volumes. Furthermore, restimulation of existing wells is not an area that has received as much attention as other areas, and, where it has, the focus has been on simply repeating refracturing with proppant. Remedial chemical-treatment options have not been explored to a significant extent, especially at the field level. Instead, greater attention has been placed on how to make the leap from primary production achieved from initial well completion to field-scale enhanced oil recovery (EOR). The in-between measure of remedial production enhancement in existing wells is largely being skipped. 

With low primary-recovery rates in unconventional reservoirs and the longer-term development prospects for EOR applications on a fieldwide scale, the potential for accelerated completion optimization in new wells and production-enhancement treatments in existing wells is substantial and perhaps comes with more immediate returns. 

Along those lines, the first of three papers featured this month addresses the optimization of fracture spacing and penetration ratio in unconventional reservoirs. The other two papers discuss studies related to remedial production and recovery improvement in existing wells—surfactant soak and flowback treatments in oil-bearing formations and solvent treatments for water and condensate blockage in tight formations, respectively.

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

SPE 189805 Dual-Permeability Matrix-Fracture Corefloods for Studying Gasflooding in Tight Oil Reservoirs by Peng Luo, Saskatchewan Research Council, et al.

SPE 190214 Underlying Mechanisms of Tight Reservoir Wettability and Its Alteration by Peng Luo, Saskatchewan Research Council, et al.

SPE 187542 Limitation of EOR Applications in Tight Oil Formation by Ahmed Mansour, Texas Tech University, et al.
Technology Focus: Sand Management and Sand Control (October 2018)
Authors: Wang Xiuli
Published: October 2018

Technology Focus

Rig count and fracturing-crew activity are the pulse of the energy industry; as energy commodity prices increase, so do these vital numbers.

During the past year, crude oil prices jumped 36% from $49.59/bbl (WTI) at the beginning of August 2017 to $67.68/bbl on 1 August 2018, with a maximum price of approximately $74/bbl in late June 2018.

The price increase experienced during the past year has renewed investments in many plays. However, a long-term project, such as offshore deepwater field developments, would require a minimum sustainable oil price to be profitable. We, therefore, have not seen massive investment in developing challenging sand-prone fields that require large capital investment up front to complete wells with expensive and sophisticated sand-management and -control techniques. Perhaps the demand has not yet justified sustainable prices, leading some oil companies to rebalance capital allocation by increasing dividend payouts or stock repurchasing programs while waiting for the market forces to establish a price benchmark.

In this respect, in the energy industry, no news very often is the best news; any geopolitical instability and tensions could cause oil prices to fluctuate abruptly and make operators feel uneasy about investing in capital-intensive projects.

On the technology side, regardless of the oil price, demand persists for cost-saving and value-adding innovations and emerging technologies to bridge gaps in the existing technology portfolio for sand management and control.

To stay in the know of the latest projects trending in the energy industry, read the featured papers and recommended additional reading and attend the upcoming 2018 SPE Annual Technical Conference and Exhibition 24–27 September in Dallas and the Asian Pacific Oil and Gas Conference 23–25 October in Brisbane, Australia.

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

SPE 187237 Self-Assembling Nanoparticles: A Unique Method for Downhole Sand Consolidation by Rajendra Kalgaonkar, Saudi Aramco, et al.

SPE 189491 Openhole Mechanical Packer With Eccentric Shunt-Tube Gravel-Pack Assembly Reduces CAPEX and Accelerates Production in Laombo Deepwater Development, Angola by J. Hernandez, Total, et al.

SPE 189557 A Large-Scale Sand-Retention Test Facility for Evaluation and Selection of Optimal Standalone Sand Screen for Injection Wells in Thermal Operations by M. Mahmoudi, RGL Reservoir Management, et al.
Stimulation of High-Temperature Steam-Assisted-Gravity-Drainage Production Wells Using a New Chelating Agent (GLDA) and Subsequent Geochemical Modeling Using PHREEQC
Authors: Ameur Z. Ouled , Kudrashou V. Y. , Nasr-El-Din H. A. , Forsyth J. P. , Mahoney J. J. , Daigle B. J.
Published: October 2018

The acidizing of sour, heavy-oil, weakly consolidated sandstone formations under steam injection is challenging because of fines migration, sand production, inorganic-scale formation, corrosion issues, and damage caused by asphaltene precipitation associated with these sandstone formations. These and other similar problems cause decline in the productivity of the wells, and there is a recurring need to stimulate them to restore productivity. The complexity of sandstone formations requires a mixture of acids and several additives, especially at temperatures up to 360°F, to accomplish successful stimulation. Three treatments were tested on a horizontal well in the field: hydrochloric acid (HCl); Chelating Agent B, a high-pH chelant; and Chelating Agent A, or glutamic acid Ν,Ν-diacetic acid (GLDA). The first two treatments with 15 wt% HCl and high-pH (pH = 10) Chelating Agent B produced results below expectations. The third treatment using GLDA was successful, and the well productivity increased significantly. The field treatment with GLDA included pumping the treatment fluid, which was foamed to create proper rheological characteristics and a better-controlled pumping process. The treatment fluids were displaced into the formation by pumping produced water and were allowed to soak for 6 hours. In this paper, we evaluate the field applications of GLDA using geochemical modeling, production data, and analysis of well-flowback fluids after the field treatments.
Automatic Optimization of Oilfield-Scale-Inhibitor Squeeze Treatments Delivered by Diving-Support Vessel
Authors: Vazquez Oscar , Ross Gill , Jordan Myles M. , Baskoro Dionysius Angga , Mackay Eric , Johnston Clare , Strachan Alistair
Published: October 2018

Oilfield-scale deposition is one of the important flow-assurance challenges facing the oil industry. There are a number of methods to mitigate oilfield scale, such as reducing sulfates in the injected brine, reducing water flow, removing damage by using dissolvers or physically by milling or reperforating, and inhibition, which is particularly recommended if a severe risk of sulfate-scale deposition is present. Inhibition consists of injecting a chemical that prevents the deposition of scale, either by stopping nucleation or by retarding crystal growth. The inhibiting chemicals are either injected in a dedicated continuous line or bullheaded as a batch treatment into the formation, commonly known as a scale-squeeze treatment. In general, scale-squeeze treatments consist of the following stages: preflush to condition the formation or act as a buffer to displace tubing fluids; the main treatment, where the main pill of chemical is injected; overflush to displace the chemical deep into the reservoir; a shut-in stage to allow further chemical retention; and placing the well back in production. The well will be protected as long as the concentration of the chemical in the produced brine is greater than a certain threshold, commonly known as minimum inhibitor concentration (MIC). This value is usually between 1 and 20 ppm. The most important factor in a squeeze-treatment design is the squeeze lifetime, which is determined by the volume of water or days of production where the chemical-return concentration is greater than the MIC.

The main purpose of this paper is to describe the automatic optimization of squeeze-treatment designs using an optimization algorithm, in particular particle-swarm optimization (PSO). The algorithm provides a number of optimal designs, which result in squeeze lifetimes close to the target. To determine the most efficient design of the optimal designs identified by the algorithm, the following objectives were considered: operational-deployment costs, chemical cost, total-injected-water volume, and squeeze-treatment lifetime. Operational-deployment costs include the support vessel, pump, and tank hire. There might not be a single design optimizing all objectives, and thus the problem becomes a multiobjective optimization. Therefore, a number of Pareto optimal solutions exist. These designs are not dominated by any other design and cannot be bettered. Calculating the Pareto is essential to identify the most efficient design (i.e., the most cost-effective design.)
Effect of Ferric Oxide Nanoparticles on the Properties of Filter Cake Formed by Calcium Bentonite-Based Drilling Muds
Authors: Mahmoud Omar , Nasr-El-Din Hisham A. , Vryzas Zisis , Kelessidis Vassilios C.
Published: October 2018

During the past few decades, nanoparticles (NPs) have been investigated as additives to address the challenges of drilling fluids and have shown potential for application. The present work focuses on introducing and investigating a calcium (Ca) bentonite-based drilling fluid with ferric oxide (Fe2O3) NPs.

Generating efficient filter cake is an important property of the drilling fluid and can affect the success of the whole drilling operation. This study aims at characterizing the filter cake produced by Ca bentonite-based drilling fluid modified using Fe2O3 NPs. Computed-tomography (CT) scan and scanning electron microscopy energy dispersive spectroscopy (SEM-EDS) were used for filter-cake characterization. The effects of NP concentration and filtration conditions on the filter-cake properties were investigated. A high-pressure/high-temperature (HP/HT) American Petroleum Institute (API) filter press was used to perform static and dynamic filtrations. Indiana limestone disks were used as filter media to simulate formation behavior.

The modified Fe2O3 NPs/Ca bentonite fluid showed improved filter-cake and filtration properties in the presence of polymers and other additives. A concentration of less than 1 wt% of NPs is preferred for generating a good-quality filter cake. The best characteristics were obtained when using an NP concentration of 0.3 to 0.5 wt%. The NPs/Ca bentonite-based drilling fluid can withstand conditions up to 500 psi and 350°F and generate filter-cake properties of 0.151-in. thickness, 6.9-cm3/30-min filtrate volume, and 0.449-µd permeability. Fe2O3 NPs improved the filter-cake properties under both static and dynamic conditions. SEM-EDS showed a smoother/less-porous filter-cake morphology with less agglomeration when using NPs at optimal concentrations, which confirms that the NPs play a key role in forming a better filter-cake structure.

The present work provides an experimental evaluation of the filter cake generated by modified NPs/Ca bentonite-based drilling fluid at downhole conditions, which is an extension of our previous work using a simple NPs/Ca bentonite suspension (Mahmoud et al. 2018). The improved properties of the filter cake confirmed the effectiveness of using Ca bentonite modified with Fe2O3 NPs to formulate a drilling fluid that can effectively be used for drilling practices.
Capillary Pressure and Wettability Indications of Middle Bakken Core Plugs for Improved Oil Recovery
Authors: Karimi Somayeh , Kazemi Hossein , Simpson Gary A.
Published: October 2018

Understanding reservoir-rock characteristics and the forces that mobilize oil in unconventional reservoirs is critical in designing oil-recovery schemes. Thus, we conducted laboratory experiments for three preserved Middle Bakken cores using centrifuge and nuclear-magnetic-resonance (NMR) instruments to understand oil-recovery mechanisms in the Bakken. Specifically, we measured capillary pressure, pore-size distribution (PSD), and oil and brine saturations and distributions.

A series of oil/brine-replacement experiments (drainage and imbibition) were conducted for the preserved cores using a high-speed centrifuge. T2 time distribution and 1D saturation-profile measurements were obtained using a 2-MHz NMR instrument before and after centrifuge experiments. Moreover, PSD was determined from mercury-intrusion capillary pressure (MICP) and nitrogen-gas-adsorption experiments. We conducted scanning-electron-microscope (SEM) imaging on polished cubical cores to determine pore shapes and mineralogy of pore walls using a field-emission SEM (FE-SEM).

Our measurements show that these three preserved Middle Bakken cores show mixed-wet characteristics. Water resides in smaller pores and oil resides in larger pores in all experiments. Using a low-salinity synthetic brine of 50,000 ppm to surround Bakken cores of much-higher salinity, we produced up to 6.33% [of pore volume (PV)] oil from two higher-porosity (approximately 8%) cores, and 10.72% (of PV) oil from one lower-porosity (approximately 2%) core in a spontaneous-imbibition (SI) experiment. Up to 6.62% (of PV) oil from the two higher-porosity cores and 11.23% (of PV) oil from the lower-porosity core were produced in a forced-imbibition (FI) experiment as well. These experiments indicate that molecular diffusion/capillary osmosis overrides the wettability effects in low-permeability Middle Bakken cores. The new observations regarding molecular diffusion/capillary osmosis have altered our classical notion of capillary imbibition in low-permeability reservoirs.
Thermodynamic Behavior of Olefin/Methane Mixtures Applied to Synthetic-Drilling-Fluid Well Control
Authors: Marques D. C. , Ribeiro P. R. , Santos O. L. , Lomba R. F.
Published: October 2018

The presalt hydrocarbon discoveries in Brazilian deep water have been a challenging environment for drilling operations as a result of the technical demands and restrictions and the environmental regulations driving scientific and technological development.

In this drilling context, an accurate estimation of the downhole pressure is mandatory to avoid drilling problems such as kicks, lost circulation, and wellbore instability. When considering kick prevention and control, understanding of the mixture behavior (drilling fluid and formation gas) is essential to improve the estimation of the downhole pressure, which would support efficient, safe, and economic drilling operations.

The widespread application of synthetic-based drilling fluids in the Brazilian presalt polygon is justified by the technical performance offered by this kind of drilling fluid, such as reduced drilling time compared with water-based drilling fluids, increased lubricity in directional and horizontal wells, and shale-swelling inhibition. In addition, this is an environmentally friendly alternative to oil-based drilling fluids. However, those fluids are more sensitive to pressure and temperature variations than water-based drilling fluids. To obtain a better understanding of the behavior of one specific kind of synthetic-based drilling fluid, the olefin experimental research was conducted and the results and findings are presented in this technical article. The work involved pressure/volume/temperature (PVT) measurements for olefin/methane mixtures to investigate the effect of pressure, temperature, and mixture composition on thermodynamic properties such as density, formation volume factor (FVF), gas-solubility ratio, and saturation pressure. Those properties are important for knowledge of the mixture volumetric behavior at downhole conditions, especially when gas enters the wellbore.

The experiments were conducted at isothermal conditions, and a gas-enrichment experimental procedure was applied. The temperature range was from 25 to 80°C (77 to 176°F), the gas molar fraction (GMF) ranged from 30 to 50%, and pressure was up to 69 MPa (10,000 psi).

In addition, the measured data were compared with an existing database (Silva et al. 2004; Atolini 2008) for methane/n-paraffin mixtures, as well as for methane/ester mixtures (Kim et al. 2015). Pit-gain analyses were also performed according to the procedure of Monteiro et al. (2010), and a comparison of the results with other base fluids showed interesting findings.
Concerns and Clarifications for Drilled Uncompleted (DUC) Wells in the Williston Basin
Authors: Srinivasan Karthik , Krishnamurthy Jayanth , Kaufman Peter
Published: October 2018

The recent slump in oil prices has resulted in new terminology: “drilled uncompleted wells,” often referred to as DUC wells by the industry. In 2013 and 2014, when oil prices were more than USD 100/bbl, rate of return (ROR) from most unconventional plays was in the range of 15 to 50%, depending on the quality of rock and the operator's portfolio in the basin. The objective of this paper is to address key challenges associated with DUC completions when they are eventually fractured and brought on line for production. The paper addresses four main concerns that can have significant impacts on productivity of DUC wells: fracture hits (well interference), reservoir quality (hydrocarbon drainage), multiple horizons (zone connectivity), and well spacing (high-density drilling). The paper also showcases case studies in which real-time observations made from wells have been used to validate predictions from forward-looking fracture and production models.

First, fracture hits commonly have been observed in all unconventional plays throughout the US, with effects on offset wells being mixed. Some fracture hits result in a positive uptick in production in offset wells, whereas other fracture hits affect production negatively in the form of increased water cut, reduced wellhead pressure, and other responses. Understanding fracture hits and their influence on other wells is very critical to avoid any detrimental impacts or to leverage positive effects on production. Second, reservoir quality decides how much oil in place is available for the DUC wells to drain, which, in turn, depends on length of production history and parent-well-completion geometries in offset wells. Third, in basins where there are multiple producing horizons or formations, fracture-height growth and interference between adjacent formations can result in asymmetric fracture propagation toward depleted zones. The longer these wells completed in the same/adjacent formations have been on production, the greater the extent of asymmetry will be. Addressing this concern requires a good understanding of drainage patterns from offset wells and evaluation of their impact on fracture geometries in DUC wells. Last, in areas with high-density drilling, a combination of longer production and fracturing stages with multiple perforation clusters per stage can leave very little oil available for the DUC well to produce.
Proppants—What 30 Years of Study Have Taught Us
Authors: Duenckel R. J. , Barree R. D. , Drylie S.. , O’Connell L. G. , Abney K. L. , Conway M. W. , Moore N.. , Chen F..
Published: October 2018

The earliest hydraulic-fracture stimulations used poorly sorted river sand as the proppant. Since this first experiment with proppants, the industry has evolved to offer a broad range of proppant choices although, by far, natural sand of some type remains the proppant of choice for a variety of reasons. For the past 30 years, an industry Consortium has engaged in a continuous program of building knowledge and understanding in the behavior of all types of proppants used in hydraulic fracturing.

There are many basic understandings about the behavior of proppant packs under downhole reservoir conditions that have been developed through thousands of tests that have been performed through this work. These include the effects of proppant type, grain failure, fines migration, embedment, non-Darcy and multiphase flow, cycling, loading, packing arrangement, fracture-fluid damage, and others. All these effects can be at work simultaneously to negatively affect flow in the propped fracture, and the recognition of these effects assists in explaining observed well performance.

This paper will present current knowledge of proppant performance that is sometimes misunderstood or wrongly applied and will assist the practicing engineer in well diagnostics and stimulation design.
Effect of Dilute Acid on Hydraulic Fracturing of Carbonate-Rich Shales: Experimental Study
Authors: Weldu Teklu Tadesse , Park Daejin , Jung Hoiseok , Amini Kaveh , Abass Hazim
Published: October 2018

Matrix and fracture permeability of carbonate-rich tight cores from Horn River Basin, Muskwa, Otter Park, and Evie Shale formations, were measured before and after exposing the core samples to spontaneous imbibition using dilute acid [1- or 3-wt% hydrochloric acid (HCl) diluted in 10-wt% potassium chloride (KCl) brine]. Permeability and porosity were measured at net stress between 1,000 and 5,000 psia. Brine and dilute-acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. The following are some of the experiment observations: (a) Formation damage caused by water blockage of water-wet shales can be improved by adding dilute HCl or by using hydrocarbon-based fracturing fluids; (b) matrix permeability of clay-rich or calcite-poor shale samples is usually impaired/damaged by dilute-acid imbibition; (c) matrix permeability and porosity of calcite-rich shales usually improved with dilute-acid imbibition; (d) effective fracture permeability of unpropped calcite-rich shales is reduced by dilute-acid imbibition; the latter is because of “rock softening” and “etching/smoothing” of fracture roughness on the “fracture faces.” Nevertheless, dilute-acid imbibition is less damaging than brine (slickwater) imbibition; and (e) proppant embedment was observed during both brine (slickwater) and dilute-acid imbibition. Hence, experimental results of this study imply that dilute-acid injection/imbibition/fracturing in carbonate-rich shale reservoirs can lead to hydrocarbon-production improvement caused mainly by the matrix/permeability improvement.
Analyzing Unexpected Sanding Issues in the High-Pressure/High-Temperature, Tight-Sandstone Keshen Gas Reservoir, Western China
Authors: Yang Xiangtong , Qiu Kaibin , Zhang Yang , Huang Yongjie , Fan Wentong , Pan Yuanwei , Xu Guowei , Xian ChengGang
Published: October 2018

Keshen is a high-pressure/high-temperature (HP/HT) tight-sandstone gas reservoir with reservoir pressure greater than 110 MPa and temperature more than 175°C. The sandstone is hard, with unconfined compressive strength (UCS) greater than 100 MPa. Given the HP/HT nature and natural-fracture systems in the reservoir, with aid of stimulation, many wells produced at a high rate, with the mean value exceeding 500 000 m3/d. In the last few years, many production wells in this reservoir experienced severe sanding issues that contradicted the conventional understanding that sanding would not occur in such hard rock. The sanding wells exhibited large fluctuations of production rate and wellhead pressure, erosion of chokes and nozzles, and eventually major or even complete loss of production. A solution to address the sanding issues was urgently needed because they had caused a major decline in production and resulted in significant economic loss.

Because of the unconventional nature of the sanding issues, the typical sanding-prediction methods dependent on evaluating rock failure were not adequate to reveal the underlying sanding mechanism and develop a viable operational solution. To this end, a new work flow was formulated and applied to this study. The work flow started with detailed data mining on the large amount of drilling, completion, stimulation, and production data of more than 51 wells from this reservoir to investigate possible relationships of drilling practices, completion options, and production schedules to the occurrence and severity of sanding issues. The analysis revealed that downhole flow velocity and production drawdown were the two major controlling factors in the occurrence of sand production. Further geomechanics simulation and particle-migration simulation with a multiphase dynamic flow simulator confirmed that the production drawdown would cause failure of the rock near the wellbore and the gas flow could transport the sand debris to the wellbore and lift it up to the surface. In addition, the fluctuation of production rate was caused by blockage because of the accumulation of sand particles in the wells and production tubing that were flushed out after downhole-pressure buildup.

Using the analysis, the threshold of flow velocity and the threshold of drawdown were identified, and these thresholds can be used in the reservoir management to effectively address the sanding issues.

The experience in Keshen shows that sanding is possible in HP/HT high-productivity sandstone gas reservoirs, even in an extremely hard formation, which overturns some prior conceptions on sanding. The information shared from this paper could attract the attention of those operating similar HP/HT tight-sandstone reservoirs around the world.
3D Hydraulic-Fracture Simulation Integrated With 4D Time-Lapse Multicomponent Seismic and Microseismic Interpretations, Wattenberg Field, Colorado
Authors: Alfataierge A.. , Miskimins J. L. , Davis T. L. , Benson R. D.
Published: October 2018

The 3D hydraulic-fracture-simulation modeling was integrated with 4D time-lapse seismic and microseismic data to evaluate the efficiency of hydraulic-fracture treatments within a 1 sq mile well-spacing test of Wattenberg Field, Colorado. Eleven wells were drilled, stimulated, and produced from the Niobrara and Codell unconventional reservoirs. Seismic monitoring through 4D time-lapse multicomponent seismic data was acquired by prehydraulic fracturing, post-hydraulic fracturing, and after 2 years of production. The results from the simulation modeling and seismic monitoring show the significant effect of reservoir heterogeneity on hydraulic-fracture stimulation and hydrocarbon production.

A hydraulic-fracture-simulation model using a 3D numerical simulator was generated and analyzed for hydraulic-fracturing efficiency and interwell fracture interference between the 11 wells. The 3D hydraulic-fracture simulation is validated using observations from microseismic and 4D multicomponent [compressional-wave (P-wave) and shear-wave (S-wave)] seismic interpretations. The validated 3D simulation results reveal that variations in reservoir properties (faults, rock-strength parameters, and in-situ stress conditions) influence and control hydraulic-fracturing geometry and stimulation efficiency.

The integrated results are used to optimize the development of the Niobrara Formation within Wattenberg Field. The valuable insight obtained from the integration is used to optimize well spacing, increase reserves recovery, and improve production performance by highlighting intervals with bypassed potential within the Niobrara. The methods used within the case study can be applied to any unconventional reservoir.
Dendritic-Acidizing Update: The Light at the End of the Tunnel
Authors: Wehunt C. Dean , Lattimer Stefan K. , McDuff Darren R.
Published: October 2018

In this paper, we provide an update on recent advances for and summarize global experiences with dendritic-acidizing (DA) methods, or acid tunneling. We include both coiled-tubing (CT) deployed methods and non-CT methods, and discuss process limitations, candidate-selection criteria, job-design factors, operational learnings, risks, and surveillance requirements and opportunities. A comprehensive review of published information is provided for three different tunneling methods along with relevant information for several other tunneling methods. This literature information is supplemented by depth, temperature, and pressure records for the three processes, which are discussed in detail. Execution factors such as logistics required, length of time required, and volumes of acid and other fluids used are also compared for the three methods.

Previous papers have focused on only one of the methods, whereas we will discuss acid-job optimization, process risks, and surveillance requirements for multiple acid-tunneling methods in substantially greater depth than have past authors. The three methods detailed in this paper are all viable but may have different niches. Differences in the job counts for the different methods are easily explained by differences in process vintages, execution speeds, and depth limitations. Previous optimization efforts were focused on tunnel creation but not acid-job effectiveness in terms of the wormholes generated adjacent to the tunnels; however, some progress is now being made in that regard. There are differences in the processes regarding pushing or pulling the jetting nozzles into the tunnels, and differences in resulting tunnel trajectories. Prejob caliper data are more critical for one of the processes than for the others, and there are significant differences in ability to measure or control tunnel direction. The tunneling tools have different sizes, but when tool-size alternatives are available, the larger tool sizes offer no clear advantages to the operator. Useful risk-mitigation measures are also discussed, and a comprehensive bibliography is included to facilitate further examination of the technology alternatives by other petroleum-industry professionals.
Cocurrent Spontaneous Imbibition In Porous Media With the Dynamics of Viscous Coupling and Capillary Backpressure
Authors: Andersen Pål Østebø , Qiao Yangyang , Standnes Dag Chun , Evje Steinar
Published: October 2018

This paper presents a numerical study of water displacing oil using combined cocurrent/countercurrent spontaneous imbibition (SI) of water displacing oil from a water-wet matrix block exposed to water on one side and oil on the other. Countercurrent flows can induce a stronger viscous coupling than during cocurrent flows, leading to deceleration of the phases. Even as water displaces oil cocurrently, the saturation gradient in the block induces countercurrent capillary diffusion. The extent of countercurrent flow may dominate the domain of the matrix block near the water-exposed surfaces while cocurrent imbibition may dominate the domain near the oil-exposed surfaces, implying that one unique effective relative permeability curve for each phase does not adequately represent the system. Because relative permeabilities are routinely measured cocurrently, it is an open question whether the imbibition rates in the reservoir (depending on a variety of flow regimes and parameters) will in fact be correctly predicted. We present a generalized model of two-phase flow dependent on momentum equations from mixture theory that can account dynamically for viscous coupling between the phases and the porous media because of fluid/rock interaction (friction) and fluid/fluid interaction (drag). These momentum equations effectively replace and generalize Darcy's law. The model is parameterized using experimental data from the literature.

We consider a water-wet matrix block in one dimension that is exposed to oil on one side and water on the other side. This setup favors cocurrent SI. We also account for the fact that oil produced countercurrently into water must overcome the so-called capillary backpressure, which represents a resistance for oil to be produced as droplets. This parameter can thus influence the extent of countercurrent production and hence viscous coupling. This complex mixture of flow regimes implies that it is not straightforward to model the system by a single set of relative permeabilities, but rather relies on a generalized momentum-equation model that couples the two phases. In particular, directly applying cocurrently measured relative permeability curves gives significantly different predictions than the generalized model. It is seen that at high water/oil-mobility ratios, viscous coupling can lower the imbibition rate and shift the production from less countercurrent to more cocurrent compared with conventional modeling. Although the viscous-coupling effects are triggered by countercurrent flow, reducing or eliminating countercurrent production by means of the capillary backpressure does not eliminate the effects of viscous coupling that take place inside the core, which effectively lower the mobility of the system. It was further seen that viscous coupling can increase the remaining oil saturation in standard cocurrent-imbibition setups.