bluuebunny/crossref_metadata_2025_split huggingface dataset:
Want More Production? Try Taking a Break
Authors: Rassenfoss Stephen 
Published: February 2020

Apache found something positive to say about its huge gas-producing play in the Permian at a time when gas is selling at rock-bottom prices.
When it shut in a 14-well pad on its Alpine High play for 60 days, gas and condensate production surged. It was a rare test of whether a production break can allow water in rock near the fracture face to soak in deeper, allowing gas and liquids to flow more freely.
“The gas rate came back above the pre-soak rate and it’s actually holding in pretty flat, so it shows there was some impact and the condensate rate came in higher than the pre-soak rate,” said Dave Pursell, executive vice president of planning, reserves and fundamentals, during the company’s third quarter earnings call.
The wells were on the huge Blackfoot pad, which Apache had highlighted a year ago as a major test of the industry trend toward concentrating many wells at a single location to reduce development costs. In mid-2018, the company said the pad was producing 99 mm ft3/d, and 200 B/D of oil from 12 wells.
Based on the comment during the call, production since then has been disappointing.
“We thought, let’s take advantage of low commodity prices and initiate a 60-day soak to really understand whether it is a relative permeability issue or what is the mechanism for the underperformance,” Pursell said.
The price of doing the test was a significant decline in Alpine High production—Apache said the shut-in was a prime reason for a 30% drop in production there. But with gas prices so low, the expected upside apparently justifies the revenue delayed.
During that earnings call, Apache also said it would reduce the number of rigs working in the Alpine High play from five to two so it could concentrate on Permian Basin acreage.
Stories about the benefits of soaking have been around for a long time. As has talks about its downsides. In those cases, production was not an option, often due to lack of pipeline access or processing facilities.
Apache tried soaking on the big pad because, “a significant amount of water was pumped into a small area of the reservoir, which may have impacted well productivity,” Pursell said.
To answer that question and others, Pursell said Apache has “a team of folks working on the Blackfoot and all the multiwell pads we drilled and completed to date.”
Is It Worth It?
Apache is getting in the middle of an argument over whether soaking is worth the production days lost. While it often does cause a production spurt, the gains can quickly fade and skeptics argue that soaking can cause clay-rich rocks to swell, causing damage.
Robert Hawkes, general manager at Abra in Canada and an SPE Distinguished Lecturer, has long advocated soaking. He said the industry needs to realize that water’s impact goes beyond fracturing rock and delivering sand to prop fractures.
Technology Focus: Drilling Innovation (February 2020)
Authors: Weatherl Michael H. 
Published: February 2020

Technology Focus
Summer jobs working on drilling rigs in western Oklahoma and California in 1980 and ’81 were great adventures. High oil and gas demand meant major and independent operators used some of the latest, state-of-the-art rigs to probe deep into high-pressure reservoirs. Planning and executing wells back then was a manual process with experience, horsepower, pencil, and calculator. My adventures continued after I graduated from college in 1982. Ever-evolving drilling, completion, and subsurface technology characterized the years that followed.
Fast forward to February 2020. “The more things change, the more they stay the same,” the old-timers might say. In many field locations today, old-school machinery and processes remain in place. However, we see artificial intelligence (AI), data analytics, machine learning, and related advancements transforming our industry. These developments have been headlines for several years now but will take more time to reach full fruition. Experts agree this is just the beginning. Jensen Huang, chief executive officer and founder of Nvidia, highlighted this during a CNBC interview in November. “We are at the beginning of the AI revolution, one of the most powerful technological forces of all time,” he said. “We’ve created the ability for computers to understand the code of human knowledge. All industries will be transformed.” Huang, an AI visionary, showed a 4D simulation of an unmanned Mars landing craft on final approach going from 12,000 mph to zero in 6 minutes. Such visionaries are also working in upstream exploration and production to achieve remarkable advancements.
A focus on drilling innovation reveals no shortage of SPE papers that exemplify these exciting trends. Without exception, the featured articles reflect increased volumes of surface and downhole data that are being captured and analyzed to enable deep learning, improved efficiency, safety, and value. As noted in paper OTC 29487, oil and gas companies are creating layers of digital knowledge enabling a new generation of AI-driven applications. New insights into mitigation of drillstring vibration, well-control events, and rate-of-penetration optimization follow. Managed-pressure drilling remains a persistent trend that continues to evolve across onshore, offshore, and geographical boundaries, opening new frontiers once seen as out of reach. One need not look to outer space to imagine the extent of breakthroughs to come in the not-too-distant future.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE/IADC 194535 Nitrogen-Cap Drilling: A Managed-Pressure-Drilling Alternative for Highly Fractured Carbonate Reservoirs by Alexey Podust, Tengizchevroil, et al.
SPE 196166 Standardization: Successful Implementation of Driving Consistency in Deepwater Operations by Daniel A. Durey, Shell, et al.
SPE 197942 Innovative Digital Well-Construction-Planning Solution Enhances Coherency and Efficiency of the Drilling-Design Process by Waldemar Szemat-Vielma, Schlumberger, et al.
Emulsified Polymer Gel Pickering Emulsion for Conformance Control: Emulsion Formulation, Stability and Coreflooding Investigation
Authors: Saikia Tinku , Sultan Abdullah , Barri Assad , Shamsan Abdulmalek 
Published: February 2020

Abstract
The water production from the oil wells not only increases the per barrel oil production cost but also raises environmental concerns. The use of conventional water shut-off techniques not only restricts the production of water but also reduces the oil production. The use of emulsified polymer gel system presents an efficient way for conformance control in the oil reservoirs. The emulsified polymer gel system was designed in such a way that it will separated into oleic and aqueous phase encountering higher reservoir temperature. The aqueous phase will become gel and provides the resistance towards the water flow whereas the oil phase will provide the passage to oil, towards the production well. In this research work, an emulsified polymer gel system was developed having polyacrylamide and polyethylenimine as aqueous phase and diesel as oleic phase. The organoclay Cloisite 20A was used as an emulsifier. The emulsified polymer gel system was characterized by dilution test, microscopic analysis and gel strength code. The developed emulsified polymer gel was found to be water-in-oil emulsion system, which formed rigid gel (gel strength grade-I) under reservoir temperature conditions. The thermal stability of the emulsion system was tested at 105°C. The emulsion stability index of the emulsified gel system was also calculated. To check the effectiveness of the developed emulsified gel system for conformance control, core-flooding experiment was performed at 105 °C. During the core flooding experiment, the system provides desired resistance to water flow whereas allow the diesel oil to produce with ease. This indicates that the developed emulsified polymer gel system is an effective conformance control system, which can be used in high temperature reservoirs. This research work presents a core flooding experiment study, to evaluate the performance of emulsified gel system (Pickering emulsion) for conformance control in high temperature reservoirs.
Challenges and Potentials for Sand Control Design and Management in Oil Reservoirs of Kazakhstan
Authors: Soroush Mohammad , Hosseini Seyed Abolhassan , Roostaei Morteza , Pourafshary Peyman , Mahmoudi Mahdi , Ghalambor Ali , Fattahpour Vahidoddin 
Published: February 2020

Abstract
Kazakhstan owns one of the largest global oil reserves (~3%). This paper aims at investigating the challenges and potentials for production from weakly-consolidated and unconsolidated oil sandstone reserves in Kazakhstan.
We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves, in Kazakhstan, were studied in terms of the depth, pay-zone thickness, viscosity, particle size distribution, clay content, porosity, permeability, gas cap, bottom water, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, geological condition, including the existing structures, layers and formations were addressed for different reserves.
Weakly consolidated heavy oil reserves in shallow depths (less than 500 m) with oil viscosity around 500 cP and thin pay zones (less than 10 m) have been successfully produced using cold methods, however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical in comparison to the similar cases in North America. The complicated tectonic history, necessitates the geomechanical models to strategize the sand control especially in cased and perforated completion. These models are usually avoided in North America due to the less problematic conditions. Further investigation has shown that Inflow Control Devices (ICDs) could be utilized to limit the water breakthrough, as water coning is a common problem, which initiates and intensifies the sanding.
This paper provides a review on challenges and potentials for sand control and sand management in heavy oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
Prevention of Core Jamming and Damage During Coring Operations by Optimization of Drilling Parameters – Analysis of Case Studies
Authors: Ashena Rahman , Lotfi Mosayeb , Nascimento Andreas , Ghalambor Ali 
Published: February 2020

Abstract
Coring is a considerably costly drilling operation, but vital to retrieve valuable sources of ground-truth data in the oil and gas industry. To justify the high cost of this operation, essentially, cores should not undergo jamming and mechanical damage. Core jamming not only indicates an unprecedented termination of the operation, but also causes severe damage to the core column already taken in the barrel. This means that the cores cannot be retrieved with sufficient key performance indicators (KPIs); thus, it would not reliably represent reservoir properties. Reaching this significant target can be ensured not only by proper design, but also by online monitoring and investigation of the drilling parameters. This investigation predicated on several case studies in the Middle East to identify the effect of imperfect decisions made by the driller. Based on the experience and observations, the paper provides practical recommendations to alleviate the impact of such negative actions.
The drilling parameters observed in the mud logging data of six coring case studies (of several runs from three wells in carbonate reservoirs) were investigated at the depth interval just prior to jamming occurrence. These parameters consist of rate of penetration (ROP), torque, weight on the bit (WOB), rotary speed (revolutions per minute, RPM), circulation rate, and standpipe pressure (SPP). In this work, a main cause of the core jamming occurrences is discussed; that is, the improper drilling parameters application, as mismanaged by the driller. Finally, as indications of jamming, sudden variations of the drilling parameters at the specified depth were investigated. Such study can contributeto the better monitoring for future coring operations.
Based on the observations in six case studies in three wells, WOB was identified as the most significant reason causing core jamming; that is, jamming occurred when the WOB was not steadily maintained on the bit probably due to the driller’s inexperience, shift change, etc. For monitoring, torque decrease, ROP decrease, and SPP variation or decrease (following initial increases) were identified as indications of core jamming. Torque showed to be a significant parameter forjamming detection when it decreases or its trend becomes completely straight, i.e., without any variations, indicating that the core head may not be in contact with the formation. Next, drilling issues during coring (such as pump failure) can contribute to subsequent jamming.
The case studies in this paper provide several observations and indications of core jamming occurrences in a limestone reservoir which can be attributed to non-optimized drilling parameters. The paper also provides several practical recommendations and measures to prevent core jamming and core damage.
Filter Cake Breaker Evaluation for Water Injectors: Scale Up From Laboratory to Field Deployment
Authors: Chandran Pavithiran , Kumar Arunesh , Cameron Iain , Jackson Phillip , Twynam Allan , Reid Rachael , Sweeney Kieran 
Published: February 2020

Abstract
Water injection wells were planned to provide pressure support to oil producers in two North Sea fields (Field A and Field B). For both fields, water-based drilling fluid was selected to drill the reservoir section. The average permeability of the first field is 1000 mD and the second field is 50-100 mD. A laboratory study was commissioned to evaluate and optimize filter cake breaker systems for use in water injectors to efficiently remove external and internal filter cake in order to attain matrix injection without the need for backflow to clean up the sand face.
A time-delayed filter cake breaker system was chosen for evaluation as part of the study. Laboratory-scale formation damage tests indicated significant loss of injectivity, potentially due to deep invasion of xanthan polymers in core plugs along with incomplete dissolution of calcium carbonate from the filter cake. An enzyme package designed to degrade xanthan was included in the revised breaker solution and an improvement in injectivity was recorded. Further adjustments were made to the breaker formulation to optimize performance for density range, corrosion mitigation and dissolution of calcium carbonate, including allowance for the impact of the addition of lubricant to the drilling fluid.
Following an extensive and detailed study, a much greater understanding of the design, evaluation and field engineering aspects of chemical breakers has been gained. The recommendations from the study have recently been applied to injection wells on both fields.
This paper describes the test procedures adopted for evaluating the various filter cake breaker formulations and the work conducted to develop the systems to be ready for field use. The challenge and consequences around scaling up laboratory results to field conditions is particularly acknowledged. Field results are presented, highlighting both the importance of critical design issues and applied learnings for a successful outcome.
Analysis of Time Lapse Formation Damage Evolution Throughout the Life of a Well
Authors: Bellabiod Sofiane , Deghmoum Abdelhakim , Madani Habib Yssaad , Karacali Ozgur , Shumakov Yakov 
Published: February 2020

Abstract
Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters to evaluate the quality of various operations during the life of a well. The evolution of formation damage over the long run is rarely studied. This paper will present a new model of time dependent skin factor measurement. Multiple field examples are analyzed and modelled comparatively to evaluate the magnitude of the time-lapse formation damage for specific reservoir rocks.
Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and individually compute the contributing mechanisms of actual damage. Formation damage is a combined effect of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well clean up, organic substance deposition, multiphase flow effects, etc. The proposed innovative approach utilizes the skin factor in pressure transient analysis to measure the time-lapse evolution of formation damage. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type.
This paper will present an innovative technique and methodology to quantify the formation damage that has been materialized during the life of a well, from drilling to production. A robust technique to quantify the total damage is the computation of the skin factor from pressure transient tests conducted at various times. Observations confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time. Pressure transient tests conducted after drilling, casing, and perforating were analyzed. These initial pressure transient test results were compared with production tests performed years after drilling. Various field examples from North African reservoir rocks are presented to depict the applicability of the time-lapse method to quantify the formation damage for a given specific reservoir rock. Remedial stimulation work has been performed in such damaged wells. Formation damage could be removed, and the productivity has been revamped. The stimulation procedure has been based on core plug tests of various stimulation fluids. Potential stimulation strategies to remove or minimize formation damage are also discussed in this paper.
In this paper a new methodology and mathematical relation have been described to quantify the time-lapse formation damage mechanisms. Field examples from North African reservoirs have been depicted. The findings could be easily utilized to apply the time-lapse methodology for similar reservoir rocks in other parts of the globe to measure and quantify the magnitude of the formation damage.
Visualization of Flowback Aid Mechanisms Utilizing a Microfluidic Pore-Scale Device
Authors: Ren Ginger , Abedini Ali , Yang Hyuntae , Sanders Aaron 
Published: February 2020

Abstract
Using flowback additives in slickwater fracturing fluids is a relatively recent innovation, and regained permeability testing using corefloods is the preferred performance evaluation method. The coreflood rig simulates the hydraulic fracturing process by injecting the fracturing fluid through a core under relevant pressure and temperature conditions, and measures the permeability and relative permeability changes during injection. Permeability measurements indicate whether the fracturing fluid damages the formation during hydraulic fracturing that in turn reduces oil productivity during flowback. While coreflooding is useful for comparing the performance of different flowback aids, it is unable to resolve the mechanisms associated with porescale transport. The goal of this study is to directly visualize and quantify the pore-scale dynamics of fracturing fluid injection and oil flowback using a microfluidic chip device and correlate these observations to the coreflood test results. Microfluidics-based measurements provide pore-scale visual evidence of the flowback dynamics, not achievable using conventional experimental methods such as the coreflood.
Successful Wellbore Cleanup Using Environmentally Friendly Chemicals to Enhance Well Productivity
Authors: Sharma Hemant K , AlKhalifah Qasim , Al-Mulhim Abdulrahman K. , Al-Shammari Mubarak J. 
Published: February 2020

Abstract
Drilling long horizontal and multilateral wells in the oil industry helps lower the drawdown, and minimize water or gas coning, which enhances well productivity. Many of these wells are drilled using drill-in fluid (DIF), which is cleaner than conventional mud and so is considered to be less damaging to the formation. The DIF consists of polymers for building the required viscosity to transport cuttings and deposit a filter cake around the wellbore to reduce fluid loss. Most DIFs are composed of starch, cellulose or Xanthan polymers added with bridging agents of calcium carbonates and salt particles.
Even though DIF causes less formation damage than conventional mud, damage to target formations can still occur. To remove formation damage caused by DIF, a new chemical technology is tested. The new chemical technology, which breaks up the coherence and integrity of the mudcake and polymer gel, was used for wellbore cleanup with very encouraging results. In addition, the chemical is also an eco-friendly, noncorrosive bio-enzyme and is naturally biodegradable. The chemical disintegrates into its natural elements (carbon, hydrogen, oxygen and nitrogen) after converting the insoluble polymers into water soluble sugars. In addition, the chemical minimizes formation of wormholes like in acid, which helps in keeping the wellbore away from getting connected to fractures/fissures.
This paper highlights the technological advantage of using the enzyme based chemical and how homogenous wellbore cleanup/stimulation is achieved, leading to productivity enhancement and sustainable oil production.