What’s the Best Friction Reducer? You Need To Figure It Out Yourself

2021 ◽  
Vol 73 (10) ◽  
pp. 27-30
Author(s):  
Stephen Rassenfoss
Keyword(s):  
Chemical Reactions ◽  
Performance Testing ◽  
Good Method ◽  
Well Performance ◽  
Oil Companies ◽  
Industry Standard ◽  
Well Design ◽  
Reservoir Conditions ◽  
The Many ◽  
Friction Reducer

Friction reducers are expected to play critical roles in fracturing, some better than others. Shale producers are belatedly realizing that there are many variables that can alter the performance of these chemicals used to reduce the power needed to hydraulically fracture a reservoir, and in higher doses, to thicken fluid, making it possible to deliver proppant more efficiently. There are wells that can justify paying more for a friction reducer formulated to stand up to difficult chemical challenges, and others that cannot. But there is no guide that describes how these key additives perform. Those who do evaluations will realize that a lot of details about friction reducers are proprietary and no industry standard provides guidance about the information needed to thoroughly assess their compatibility with reservoir conditions. “There hasn’t been a really good method to quantitatively evaluate friction reducers and what they do,” said Paul Carman, the completion fluid advisor for ConocoPhillips, who has not figured out what that method might be. Recently, Occidental Petroleum took a stab at answering the question with a paper discussing its evaluation of friction-reducer performance. It’s not a short answer. The paper delivered at the Unconventional Resources Technology Conference (URTeC) does not offer names of the products tested, how many were tested at any stage of the process, or details that might identify top performers (URTeC 5249). Those who dig deeper and ask fracturing experts will learn that the best friction reducer will depend on the job. And money, time, and research are required to gather the data needed for informed decision making. When Occidental began working on a system to evaluate friction reducers, they found little had been written on how to do it, said Nancy Zakhour, Occidental’s well design lead, a coauthor of the paper. There was a general paper from Shell on well chemical evaluation but little else. That shows how oil companies have come to rely on others to do performance testing. The shale business has not shown much interest in chemical performance until recently. Greater attention has turned to the many details that can incrementally improve shale well performance and to the research showing how friction reducers perform badly due to chemical reactions in some wells. These are not the only additives that may be affected by chemical reactions during and after fracturing. But friction reducers have grabbed the most attention because they do a couple important jobs.

Investigation of Radiant Superheater Crossover Pipe Weld Cracking at Big Cajun II Station

2002 ◽  
Author(s):  
James P. King ◽  
Robert D. Hendrix
Keyword(s):  
Growth Curves ◽  
Performance Testing ◽  
Circumferential Welds ◽  
Root Cause ◽  
Ultrasonic Time ◽  
History Of ◽  
The Many ◽  
Stress Fatigue ◽  
Ultrasonic Shear

This paper describes the many features of a detailed investigation into the determination of a root cause for internal cracking found in the circumferential welds of radiant superheater crossover piping lines, in the Units No. 1 and 2 boilers at Big Cajun II Station in New Roads, Louisiana. The history of inside diameter, circumferential cracks dates back to 1992. The cracking had been recorded during several outages for both units. It was discovered by use of ultrasonic shear wave testing, and verified by ultrasonic time of flight diffraction methods. During each of the ensuing unit outages, the crack depths were recorded and mapped. Repairs were undertaken by machining out the complete girth weld followed by re-welding. During the interim years cracking did re-occur at many of the weld locations. In 2000, a detailed investigation into the cause of the cracking was initiated, which resulted in recommendations for resolving the ongoing problem. This detailed study included; nondestructive testing and metallurgy of removed metal samples, boiler performance testing and analysis and stress, fatigue and fracture mechanics evaluations. The detailed background, applications and results of the many and varied testing and analytical tasks are fully described herein. The main conclusion to the root cause of the cracking is identified as fatigue caused by the combined effects of thermal and pressure cycles. Recommendations are given which address the actions needed to limit or prevent re-occurrence of the cracking, including revised boiler operating procedures. In addition, a series of fatigue crack growth curves is presented, as a monitoring toot for evaluating existing cracks in the welds.

scholarly journals Production Optimization for Natural Flow and ESP Well A Case Study on Well NS-5 Mishrif Formation-Nasriya Oil Field

2020 ◽  
Vol 10 (2) ◽  
pp. 17-35
Author(s):  
Hamzah Amer Abdulameer ◽  
Dr. Sameera Hamd-Allah
Keyword(s):  
Production Rate ◽  
Production Optimization ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Pump Frequency ◽  
Individual Parameter ◽  
Well Production ◽  
Well Design ◽  
Natural Flow ◽  
Reservoir Conditions

As the reservoir conditions are in continuous changing during its life, well production rateand its performance will change and it needs to re-model according to the current situationsand to keep the production rate as high as possible.Well productivity is affected by changing in reservoir pressure, water cut, tubing size andwellhead pressure. For electrical submersible pump (ESP), it will also affected by numberof stages and operating frequency.In general, the production rate increases when reservoir pressure increases and/or water cutdecreases. Also the flow rate increase when tubing size increases and/or wellhead pressuredecreases. For ESP well, production rate increases when number of stages is increasedand/or pump frequency is increased.In this study, a nodal analysis software was used to design one well with natural flow andother with ESP. Reservoir, fluid and well information are taken from actual data of Mishrifformation-Nasriya oil field/ NS-5 well. Well design steps and data required in the modelwill be displayed and the optimization sensitivity keys will be applied on the model todetermine the effect of each individual parameter or when it combined with another one.

A Client's Fit for Purpose Solutions in Well Abandonment

2021 ◽  
Author(s):  
Yun Thiam Yap ◽  
Avinash Kishore Kumar
Keyword(s):  
Cost Effective ◽  
Well Design ◽  
Industry Standards ◽  
Cost Effective Approach ◽  
Reservoir Conditions ◽  
Standards And Regulations ◽  
Fit For Purpose ◽  
Well Abandonment ◽  
Oil Company

Abstract Typically, most of the well abandonment practice is reference to the recognized industry standards i.e. NORSOK, UK Oil & Gas and etc, and this is how the wells abandonment was carried out in the past. These practices however evolved/changed over time with lessons learnt and experiences and turn into a fit for purpose solutions for the Client. The shift in international and local standards and regulations for a robust plug and abandonment approach has placed the need for a better and long lasting permanent P&A methodology. Adhering to the existing industry standards in well abandonment is somehow not practical and not cost effective to be implemented in different part of the well, where there are major differences in local regulations, reservoir conditions, caprock thickness, well design philosophy and etc. The magnitude of abandonment cost increase is not at par with the risk reduction in long term hydrocarbon leakage. A fit for purpose solutions is recommended in closing the gap between cost and risk. Due to the extremely varied well architecture between wells, the approach to permanent abandonment varies depending on casing sizes, presence of packers and no of casings present to the caprock area. On top of that, identifying the highest depth for a placement of cement plug will reduce on the amount of plugs to be placed, saving rig time and operational time. So far, 16 idle wells have since been permanently abandoned with the systematic approach of applying caprock restoration concept and reinstating the poor isolation across caprock areas with cement with the assistance of technology to the likes of perf-wash-cement, and hydro mechanical casing cutter. These wells have successfully been abandoned as per host authority standards. This paper will explore a major local oil company’ approach to decommissioning of wells, in line with local regulations enforced, while ensuring a cost effective approach is applied in line with the available technologies.

Geochemistry: Sedimentary geochemistry: environments and processes dominated by involvement of an aqueous phase

1977 ◽  
Vol 286 (1336) ◽  
pp. 353-372 ◽  
Keyword(s):  
Aqueous Phase ◽  
Chemical Reactions ◽  
Burial Diagenesis ◽  
Oil Companies ◽  
Sedimentary Geochemistry ◽  
New Information ◽  
Mineral Assemblages ◽  
Geological Evolution ◽  
Mantle Processes ◽  
Complete Account

Crust and mantle processes yield mineral assemblages which are not generally stable in Earth surface environments. Uplift to the zone of weathering therefore initiates chemical reactions which produce quite different assemblages. The precise nature of the resulting minerals depends much upon the composition of the aqueous phase present. Erosion, sedimentation and diagenesis move weathering products through a succession of chemical environments. Further solid-solution reactions occur at each stage. Until recently, the least-well documented part of this cycle was burial diagenesis. New information provided by oil companies from their submarine exploration programmes has done much to rectify the situation. It is now possible to present a fairly complete account of the important chemical reactions occurring at each stage of the surface cycle. The major conclusion to be drawn from this exercise is that reactions involving an aqueous phase play a very important part in geological evolution as a whole.

Introduction to Problems of Candle Combustion in Buildings

2014 ◽  
Vol 923 ◽  
pp. 165-173 ◽  
Author(s):  
Jiří Souček
Keyword(s):  
Chemical Reactions ◽  
Significant Influence ◽  
Human Population ◽  
Common Denominator ◽  
Light Sources ◽  
Toxic Substances ◽  
Human History ◽  
Historical Building ◽  
High Concentrations ◽  
The Many

From the earliest times of human history are used portable light sources. First advanced devices were torches and candles, and then human population started using kerosene lamps and other more sophisticated portable light sources based on biology or electricity. Light source based on a chemical reaction has one common denominator and that is the release of fumes while fuel combustion. In these cases, it is the source of its own, which is referred to such bodies or substances in which structure is formed light. Nowadays, historically valuable buildings more often server different purpose than they were originally built. This change in use can lead to a significant influence on historical building and its life span. One of the many factors negatively affecting the life of monuments are fumes from candle combustion. Massive use of candles releases toxic substances into the environment, which in high concentrations can affect human health and can also damage due to chemical reactions historically valuable monuments

scholarly journals (250)`Elegance' and Ark 98-348: Two New Southernpea Varieties for the Mid-South

HortScience ◽  
2005 ◽  
Vol 40 (4) ◽  
pp. 1019C-1019
Author(s):  
Teddy E. Morelock ◽  
D. R. Motes ◽  
L. W. Martin ◽  
S. E. Eaton
Keyword(s):  
Yield Potential ◽  
Mature Stage ◽  
Medium Size ◽  
University Of Arkansas ◽  
Root Knot Nematode ◽  
Industry Standard ◽  
Standard Chinese ◽  
The Many ◽  
Dark Green ◽  
The University

Southernpeas, Vigna unguiculata, are a popular vegetable in the southeastern United States. Southernpeas (cowpeas) are widely known by the many different horticultural types, i.e., blackeye, pinkeye, purple hull, cream, cowder, etc. `Elegance' was widely tested under the designation Ark 96-918. It was entered in the Regional Southernpea Cooperative Trials from 1997–2002, where it performed well. It is a root-knot nematode resistant cream that exhibits an upright bush habit with concentrated pod set and good yield potential. The seed are medium size and produce a high quality canned product. `Elegance' is unique in the fact that it is a purple hull cream with the pods turning from dark green to purple when the seed reach the green mature stage. The second release, Ark 98-348, is a selection out of `Chinese Red' that is less viney and has a more concentrated pod set and maturity than the `Chinese Red' types that are commercially grown. It was tested in the observational Regional Southernpea Cooperative Trials from 2000–02. In trials at the University of Arkansas Vegetable Substation, it outyielded industry standard `Chinese Red' types Ark 93-640 and 93-641, by 30%.

scholarly journals Generalized Extreme Value Statistics, Physical Scaling and Forecasts of Oil Production in the Bakken Shale

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3641 ◽  
Author(s):  
Wardana Saputra ◽  
Wissem Kirati ◽  
Tadeusz Patzek
Keyword(s):  
Oil Production ◽  
Extreme Value ◽  
Gas Production ◽  
Extreme Value Statistics ◽  
Well Performance ◽  
Generalized Extreme Value ◽  
Potential Wells ◽  
Well Production ◽  
Industry Standard ◽  
Decline Curve

We aim to replace the current industry-standard empirical forecasts of oil production from hydrofractured horizontal wells in shales with a statistically and physically robust, accurate and precise method of matching historic well performance and predicting well production for up to two more decades. Our Bakken oil forecasting method extends the previous work on predicting fieldwide gas production in the Barnett shale and merges it with our new scaling of oil production in the Bakken. We first divide the existing 14,678 horizontal oil wells in the Bakken into 12 static samples in which reservoir quality and completion technologies are similar. For each sample, we use a purely data-driven non-parametric approach to arrive at an appropriate generalized extreme value (GEV) distribution of oil production from that sample’s dynamic well cohorts with at least 1 , 2 , 3 , ⋯ years on production. From these well cohorts, we stitch together the P 50 , P 10 , and P 90 statistical well prototypes for each sample. These statistical well prototypes are conditioned by well attrition, hydrofracture deterioration, pressure interference, well interference, progress in technology, and so forth. So far, there has been no physical scaling. Now we fit the parameters of our physical scaling model to the statistical well prototypes, and obtain a smooth extrapolation of oil production that is mechanistic, and not just a decline curve. At late times, we add radial inflow from the outside. By calculating the number of potential wells per square mile of each Bakken region (core and noncore), and scheduling future drilling programs, we stack up the extended well prototypes to obtain the plausible forecasts of oil production in the Bakken. We predict that Bakken will ultimately produce 5 billion barrels of oil from the existing wells, with the possible addition of 2 and 6 billion barrels from core and noncore areas, respectively.

Pressures and Pressure Derivatives of a Vertical Well Located Within Two Inclined Faults: Case Study of Basic Angles and Unequal Well Distances from Faults

2021 ◽  
Author(s):  
Michael Ojah ◽  
Steve Adewole
Keyword(s):  
Transient Behavior ◽  
Accurate Estimation ◽  
Maximum Point ◽  
Well Performance ◽  
Principle Of Superposition ◽  
Pressure Transient ◽  
Vertical Well ◽  
Well Location ◽  
Well Design ◽  
Diffusivity Equation

Abstract Pressure transient analysis has been used to evaluate performance of a vertical well located within two intersecting sealing faults. The nature and types of boundary affect productivity in bounded reservoirs. Well performance is strongly affected by well location with respect to the boundary, be it single, paired and parallel or paired and inclined. The goal of this research was to study pressure behavior as well as performance of a vertical well located within two intersecting sealing faults inclined at various angles θ and at unequal distances to faults. Unlike similar works previously carried out, this work can be used to study or predict pressure distribution of a well in a wedge system located at unequal distances to faults. Using the concept of images, the study proposed new models for estimating distances between image well(s) and active well. These models were applied in the solution to the dimensionless diffusivity equation to characterize pressure transient behavior of a well located at unequal distances to the inclined faults. These pressures and pressure derivatives were computed from the total pressure drop expression summing all the image wells by the principle of superposition. The MATLAB, Python and Excel software were deployed to compute all the dimensionless pressures for the different well designs. The results obtained show that 1) the proposed models give accurate estimation of active well distances to image wells; 2) the models show that the distance between the active and image wells d0,i increases for the range of values of angles 0°< θ0,i ≤ 180° and decreases for the range 180° < θ0,i < 360°; 3) the relationship between unequal well distances and productivity has a maximum point; 4) beyond this point, the well ceases to be productive and; 5) this maximum point is at equal distances of the well from both faults, in this case, 15 ft. Larger magnitudes of dimensionless pressure derivatives would indicate higher oil production for any well design and inclination of the boundaries. Worthy of future works are similar studies on 1) horizontal wells and 2) mixed boundaries, that is, one sealing fault and one constant pressure boundary.

ESPCP - An Economic Artificial Lift Method for an Offshore Field in Southwest Trinidad

2021 ◽  
Author(s):  
Nigel Ramkhalawan ◽  
Hamid Hassanali
Keyword(s):  
Operating Cost ◽  
Oil Price ◽  
Well Performance ◽  
Economic Success ◽  
Industry Standard ◽  
Recoverable Reserves ◽  
Artificial Lift ◽  
Actual Field ◽  
Project Life ◽  
Offshore Field

Abstract Frequent rod failures still occur in Progressive Cavity Pumped (PCP) wells with high dog-leg severities although they are fitted with adequate rod centralization. This results in well downtime and production deferrals. Offshore workovers are expensive and significantly affect operating cost (OPEX) of the operator. This study sought to evaluate the potential benefits of Electrica l Submersible Progressive Cavity Pumps (ESPCP) as an economic alternative for highly deviated wells in the offshore field in Trinidad. In this theoretical study, a screening criterion was established and four (4) candidates, all produced by surface driven PCPs, were selected. Models of ESPCP systems were developed using industry standard Progressive Cavity Pump software, parameters from the original PCP models as well as actual field well tests and production data. An economic evaluation, which integrated oil price and production rate sensitivities, was conducted using field data, including field reservoir characteristics and past well performance. The ESPCP model results suggest a cumulative increase of 567 BOPD is expected for all four wells. Using an oil price of US $45 per barrel, the analysis was conducted on all wells targeted for ESPCP conversion. Assuming a P50 oil rate, sensitivities were run to establish the minimum oil price for the project to be economically feasible. The operator's project economic success criteria were :(1) pay-out period of <2 years and (2) NPV of > US $0.15 Million considering a ten (10) year project. An integrated sensitivity analysis was performed for the entire project with varying expected production increases and fluctuating global oil prices. The simulations identified that the project will be uneconomic at a global oil price of US $20/bbl. Assuming a project life of 10 years and based on the expected production increase, the project is massively profitable, yielding an expected NPV of US $9.3 Million at US $45 per barrel with expected pay-out times between 0.63-1.8 years with investment of US $4 Million. Additional benefits anticipated include, increased well uptime and the corresponding reduction in workover costs. Another opportunity that results from the conversion to ESPCP, is the possibility of lowering the pump in the wellbore, thereby increasing the well producing life and increasing the recoverable reserves. Installation of ESPCPs, in theory, can be an economic success in an area where surface driven PCP experiences repetitive rod failures, leading to production deferrals and workover. Additionally, lowering the pump in the wellbore may be possible, thereby increasing the well producing life and increasing recoverable reserves which would not have been possible using traditional artificial lift methods.

Intelligent Operating Envelope Integrated with Automated Well Models Improves Asset Wide PCP Surveillance and Optimization

2021 ◽  
Author(s):  
Mohammed Al Sawafi ◽  
Antonio Andrade ◽  
Nitish Kumar ◽  
Rahul Gala ◽  
Eduardo Marin ◽  
...  
Keyword(s):  
Real Time ◽  
Optimum Operating ◽  
Well Performance ◽  
Optimum Operating Condition ◽  
Visualization System ◽  
Well Design ◽  
Well Model ◽  
Operational Activities ◽  
Petroleum Development ◽  
Well Models

Abstract Petroleum Development Oman (PDO) has been a pioneer in improving Well management processes utilizing its valuable human resources, continuous improvement and digitalization. Managing several PCP wells through Exception Based Surveillance (EBS) methodology had already improved PCP surveillance and optimization across assets. The key to trigger EBS was to keep Operating Envelope (OE), Design Limits updated in Well Management Visualization System (WMVS) after every change in operating speed (RPM), workover and new completion. The sustainable solution was required for automatic update of OEs, having well inflow potential and oil gain opportunities available for quicker optimization decisions for further improvements. PDO has completed a project automating PCP well modeling process where models are built and sustained automatically in Well Management System (WMS) for all active PCP wells, with huge impact on day-to-day operational activities. The paper discusses utilization of physics based well models from WMS to automatically update OE, identify oil gain potential daily and enable real time PCP performance visualization in WMVS. The integration of WMS and WMVS was completed to share data between two systems and automatically update well's OE daily. A tuned well model from WMS was utilized to provide well performance data and sensitivity analysis results for various RPMs. Among the various data obtained from WMS, live OE of torque and fluid above pump (FAP) for various speeds, operating limits, design limits, locked in potential (LIP) for optimization and pump upsize were utilized to process PCP well EBS and create live OE visualization. The visualization is created on a torque-speed chart where a live OE and FAP can be observed in provided picture with current RPM and torque with optimum operating condition. The project is completed after conducting successful change management across PDO assets and after thorough analysis of implementation following benefits were observed: 5% net gain of total PCP production is being executed with zero CAPEX using LIP reports. 50% of engineer's time was saved by updating OEs in WMVS automatically, reduction of false EBS and EBS rationalization. 200% improvement in PCP well performance diagnostics capabilities of Engineers. 15% CAPEX free optimization and pump upsize cases were identified based on well inflow potential. 100% visibility to PCP well's performance was achieved using well model. The visualization has supported engineers monitoring well performance in real time and easily identifying ongoing changes in well and pump performance. PCP well models have supported engineers in new PCP well design and pump upsize. The current efforts in utilizing real time well models, inferred production, automating processes to update OE is one more step toward Digitalization of PCP Surveillance and optimization and to achieve self well optimization for further improving operational efficiency.

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