bluuebunny/crossref_metadata_2025_split huggingface dataset:
Julia Case History of the Stimulation and Lower Completion to Meet the 10kpsi Drawdown Tertiary Challenge
Authors: Amoruso James D. , Templeton-Barrett Elizabeth , Hecker Michael T. , Corbell Clifford A. , Kao Gilbert , Clayton Erik H. , Hixon James D. , Garzon Jorge L. 
Published: October 2018

Abstract
The Lower Tertiary Wilcox Julia field is a large resource with low permeability (average 10 mD) and 20 cP in-situ viscosity oil. In order to achieve optimum production rates and ultimate recovery, ultra-high 10,000 psi drawdown is required from a multi-zone fracture stimulated lower completion. This paper will review design and execution details of the 4-well Phase 1 lower completion and fracture stimulation design. Results from Phase 1 will be used in future reservoir studies to determine the ultimate development plan for the Julia Field.
The Julia reservoir and geology were studied and a single well simulation model developed to determine the optimal fracture geometries required to deliver low skin completions. A "clean sheet of paper" approach was taken to brainstorm all possible completion options to achieve these fracture geometries. Further study concluded a multi-zone fractured completion was needed to cover the typical ~2000ft vertical gross pay with 4-5 zones. The fracture gel, proppant and fracture designs were then developed to meet the fracture length and conductivity requirements. Four wells were completed with excellent results yielding initial skins of −4 to −6 when skins of −2 to −3 were expected.
Four multi-zone, ultra-deep (~31000'+ TVD), ultra high reservoir pressure (~21000-22,000 psi) wells were completed successfully with initial production rates better than expected on a per well basis The completions were executed without sticking a frac tool and without loss or abandonment of any zones. Each aspect of the completion, multi-zone, fractures, proppant, fracture design and implementation was key in achieving the ability to drawdown the wells up to 10,000 psi and optimize the Julia production for Phase 1. This development shows the team's approach across multiple disciplines of geology, reservoir, and sub-surface to meet the Lower Tertiary challenge. Results from Phase 1 will allow further reservoir studies to be conducted over the next several years to determine the best ultimate development plan for Julia. Well operability limits to define the allowable drawdown and depletion were calculated. Initial production curves with drawdowns are shown.
Production Forecasting for Shale Gas Reservoirs with Nanopores and Complex Fracture Geometries Using An Innovative Non-Intrusive EDFM Method
Authors: Yu Wei , Wu Kan , Liu Malin , Sepehrnoori Kamy , Miao Jijun 
Published: October 2018

Abstract
A rigorous and efficient numerical method for simulation of shale gas production considering complex hydraulic and natural fracture geometries and multiple gas transport mechanisms in nanopores is very important to evaluate stimulation effectiveness. In this study, we present an innovative EDFM (Embedded Discrete Fracture Model) method in conjunction with the third-party compositional reservoir simulator to simulate shale gas production considering all these complexities. Through the EDFM method, complex hydraulic and natural fractures can be directly and explicitly embedded in the matrix blocks. The complex fracture geometries can easily be handled without using local grid refinement near fractures or using unstructured gridding technique. In addition, gas transport mechanisms such as non-Darcy flow, gas desorption, gas slippage and pressure-dependent matrix permeability and fracture conductivity are included in the model. The LBM (lattice Boltzmann method) was used to model gas slippage phenomenon in nanopores. We verified the EDFM method against the LGR (local grid refinement) method for dealing with simple bi-wing fractures and the computational efficiency was also compared. After validation, we applied the EDFM method to perform history matching and production forecasting for an actual shale-gas well from Marcellus shale formation. Both simple and complex fracture geometries were considered and compared. Complex fracture geometry was predicted by a fracture propagation model considering natural fractures. Through history matching, conductivities of hydraulic fractures, active and non-active natural fractures were determined. The complex fracture geometry performs better in terms of productivity than the simple fracture geometry due to a larger amount of conductive fracture surface area. The simulation results based on an actual shale-gas well show that gas desorption and gas slippage significantly affects ultimate gas recovery, which can increase gas recovery after 30 years by 46.8%. Pressure-dependent matrix permeability and fracture conductivity play a negative impact on well productivity, which can reduce gas recovery after 30 years by 14%. Hence, complex fracture geometries and gas transport mechanisms should be properly accounted for in the numerical model in order to achieve more accurate long-term production forecasting of shale-gas wells.
Is API Enough for Gamma Ray Logs, or Do We Need More?
Authors: Inanc Feyzi , Vogt Andreas 
Published: October 2018

Abstract
Gamma-ray logs are so widely used in the industry that they can easily be classified as "commodity" services provided by large and very small service companies. In addition, gamma-ray tools are designed and produced by many companies. The wireline and logging-while-drilling (LWD) variants of this equipment present a large variability of these tools, their types and services. Although the standardization effort through the "API" definition helped end the chaotic outlook in the gamma-ray log world, it did not do much to elevate gamma-ray logs from the qualitative world to the quantitative world. Frequent complaints are still expressed about wireline and LWD tools not agreeing, different size LWD tools measuring differently, and logs from different service companies providing different results.
The major issue with gamma-ray logs is that the "API" definition is valid only if the tool is run in a 4.89-in. borehole filled with fresh water. Although all gamma-ray tools are supposed to provide the same results for such a well, in the real world there is no single one-size-fits-all concept. The measurements provided by tools characterized with the University of Houston (UH) GR pit standard will stray from a reading that can be relied on to be quantitatively correct. Although this is a well-known fact and there are environmental corrections available, no standard has been defined on how to develop the corrections. Service companies have their own internal correction approaches, resulting in a large variability from company to company. The gamma-ray logs obtained from different service companies are likely to differ from each other, even though they are corrected with their own correction algorithms.
The gold standard in LWD gamma-ray logging is the agreement between LWD gamma-ray logs and wireline logs. However, under what conditions they should agree with each other is far from clear. Can one expect a 6¾-in. LWD tool to deliver comparable logs to a wireline tool when both are run in 8½-in. holes with heavy mud? There should be clear-cut definitions of the conditions under which gamma-ray logs are compared to each other to qualify the agreement between the LWD and wireline gamma-ray tools.
In this paper we discuss the characterization process of the gamma-ray tools and how they behave in boreholes different than the UH GR characterization pit. Following that, we outline the proposals for developing gamma-ray correction strategies so that gamma-ray logs become quantitative logs rather than the qualitative logs of the past. This approach provides a second-level characterization of gamma-ray logs after the "API" standardization and provides insight for petrophysicists to understand the differences between the logs from different sources and to bring those logs together in a quantitative manner.
Real Time Surface Data Driven WOB Estimation and Control
Authors: Zha Yang , Ramsay Stacey , Pham Son 
Published: October 2018

Abstract
In directionally drilled oil and gas wells, wellbore friction and tortuosity play an important role on how efficiently torque and weight-on-bit (WOB) is transferred from surface to the drill bit. Providing accurate and consistent true WOB in a real-time manner is crucial to maintaining optimum drilling efficiency. In this paper, we present a novel, automated system for estimating and controlling downhole WOB in real-time using surface data.
The new system presented here automatically consumes drill-string and wellbore information while drilling to build a drill-string model with multiple sections, each with its own length, size, heading and wellbore friction factor. An automated algorithm captures and stores off-bottom hook-load data that meet certain rig-state conditions while monitoring multiple surface data streams. A numerical optimization method is then used to solve for the friction factor distribution with depth using selected off-bottom hookload data. The friction factors are put into a torque and drag model to estimate the downhole WOB. Numerical simulation shows that using the time history of surface data rather than a single hookload reading is key to ensuring a robust solution against noisy and missing data. An active control mode is also implemented in which the driller can directly control the downhole WOB through the system.
The system was field tested on multiple horizontal wells drilled by the operator. Comparisons with downhole measurements show the system is capable of accurately predicting downhole WOB throughout the well including the lateral section. Solving the friction model using historical hookload data ensures the stability and robustness of the estimation. The distribution of friction factors with depth also help provides additional assessment of wellbore quality. An automated WOB control test was also conducted to demonstrate the system's ability to directly control downhole WOB by adjusting surface WOB according to the algorithm. The new system provides a novel way to use real time surface data to estimate and control downhole WOB
Assessing the Impact of Open Hole Gravel Pack Completions to Remediate the Observed Productivity Decline in Cased Hole FracPack Completions in Deepwater Gulf of Mexico Fields
Authors: Zaki Karim , Li Yan , Terry Clinton 
Published: October 2018

Abstract
The objective of this work is to assess the impact on productivity decline of altering the completion type in a deepwater Miocene reservoir. Typically to date, these types of assets have utilized Cased Hole FracPack (CHFP) completions as a basis of design. Wells in the Gulf of Mexico targeting the deepwater Miocene plays have seen significant Productivity Index (PI) decline within the first few years of production.
Open Hole Gravel Pack (OHGP) and Open Hole FracPack (OHFP) completion types were selected as potential alternatives to CHFP. A coupled well, reservoir and geomechanical model was created to assess the impact of multiple potential damage components on matching the observed inflow performance from production logs. The model assesses probabilistically the weighting of each of six damage mechanisms (creep, fracture conductivity, fines migration, fracture connectivity, off-plane perforation contribution and drilling/completion fluid damage) on well performance. Based on this weighting, an assessment can then be made of their impact on the alternate completion types.
Previous studies (Knobles et al. 2017) have indicated that cased hole completions are particularly susceptible to PI decline. Specifically, when unpropped perforation tunnels collapse, they reduce the inflow area into the wellbore and create a flow restriction. In higher permeability formations, the perforations not connected to the fracture (i.e. off-plane perforations) can contribute a significant portion of the well's production. It is important to note that if the connectivity and packing of the perforations is optimized and fracture is placed to within design specifications, little PI decline is observed. However, in the real world, this is not always the case. Three wells were used in this analysis. Two wells where decline was observed and a third well where no significant decline was observed. Results from the study indicated that if the two underperforming wells had utilized an OHGP completion, the PI degradation would have been mitigated. However, the upside production seen from the third well would not be attainable had the well been completed as an OHGP on an equivalent well trajectory. The results of the study also indicated that minimizing the drilling damage would be integral to the success of the OHGP completion in comparison to optimizing the completion placement in a CHFP.
The paper addresses a significant issue of PI decline affecting deepwater wells and presents a potential remediation technique based on alternate completion types. The paper also presents a new methodology based on Design of Experiment to assess the contribution of various damage mechanism while incorporating the uncertainty around each based on available measurements.
Machine Learning Analysis of Satellite Imagery for Detection of Permian Basin Water Impoundments
Authors: Adler Joshua , Scanlon Bridget , Reedy Robert 
Published: October 2018

Abstract
A private company based in Houston, Texas, collects and analyzes water source, logistics, recycling and disposal data for the upstream oil and gas industry. The company recently started applying machine learning methods to satellite imagery of the Permian Basin to identify frac water impoundments and facilitate water trading between operators. Freshwater frac pond locations in Texas are not available from any public record data source, so identification of their locations and other characteristics through satellite imagery analysis may reveal new insights about energy industry operations. The company partnered with the University of Texas Bureau of Economic Geology to analyze eleven quarters of historical central Midland Basin satellite imagery, a time series beginning in January 2016, to test correlations between frac ponds and hydraulic fracturing activity. The study identified a significant positive correlation between total frac pond surface area in the satellite imagery and IHS data on aggregate water use for hydraulic fracturing in the Midland Basin area studied. This study also found a striking 76% increase in average frac pond volume over the 27-month study period, and found that the percentage of available frac pond water injected for hydraulic fracturing grew from 11% to 20% from January 2016 to July 2017. The most notable observation from this study, however, may be that the permit-based (IHS) control data appeared to lose integrity between six and ten months prior to the study date, while the satellite-derived data appeared to maintain integrity right up to the study date. As of May 2018, the IHS data shows water injected for hydraulic fracturing in the Midland Basin dropping 90% beginning in July 2017 because of absence of complete data. The satellite data, however, shows steady growth in total frac water supply throughout that period. This timeliness-of-data comparison was not the purpose of the study, but the study conclusions were limited because reliable control data could not be obtained for the time period of about ten months prior to the study date. This suggests that oilfield market research could be improved through the use of more satellite imagery analytics versus public permit and industy reported data.
Uncertainty in Petrophysical Evaluation of Thin-Bed Reservoirs in Greater Dolphin Area, Trinidad & Tobago
Authors: Gan Thomas , Kumar Ashok , Ogiste Candice 
Published: October 2018

Abstract
Acceptable data quality for formation evaluation forms the foundation for understanding the reservoir characterization, Petrophysical properties and pay zones identification. The data quality becomes more challenging in the thin-bed reservoirs (also known as ‘Low resistivity pay’ often abbreviated as LowReP), which poses a significant trial for field development to quantify the volumes in place and producibility.
"Greater Dolphin Area" (GDA) located within the East Coast Marine Area (ECMA) off Trinidad consists of several fields out of which this paper will be focusing on the Dolphin and Starfish fields. The reservoirs consist of a series of stacked Pleistocene sands with good porosity and permeability within a three-way-dip closure against a large growth fault. Thin-beds have been observed, verified and documented throughout this area via core acquisition, core photographs and PLT analysis. As aforementioned, due to the low resistivity pay reservoirs characteristics in Starfish and Dolphin fields, these often been overlooked or interpreted to be water-bearing, when surveyed with conventional resistivity logging tools. These thinly bedded pay section hydrocarbon volumes have significantly been underestimated between 50% – 200% deposits.
Several thin-bed methodologies have been employed for the Petrophysical modelling to support the field development planning using conventional legacy approach and Shell "Low Resistivity Pay" (LowReP) based tool response modelling and inversion methods workflow to resolve the issues associated with the presence of thin beds. This paper investigates the different methods of resolving the thin bed analysis problem and demonstrates the uncertainty of the results from each methodology on the Petrophysical properties and hydrocarbon volumes estimation.
The Industrial IoT in Oil & Gas: Use Cases
Authors: Flichy Philippe , Baudoin Claude 
Published: October 2018

Abstract
Since the Industrial Internet of Things (IIoT) became its own domain, in parallel with consumer-oriented IoT, various industries have been successfully deploying such systems – initially as pilot projects, and more recently at scale. Meanwhile, the O&G industry, hurt by the price of oil, postponed investments in new technologies. Nevertheless, there are now multiple successful case studies of IIoT in O&G. This paper contains a high-level review of several such IIoT projects in O&G and aims to help the reader gauge the results achieved in this area. By examining these cases and looking at the similarities and differences with applications in other industrial sectors (transportation, water management, utilities…), the O&G industry can derive guidance in its adoption of IIoT, in particular by identifying the "lowest-hanging fruit" to improve operations and reduce human and equipment costs. While there is still confusion in terms of standards, choice of technologies, and myriad actors of all sizes, this is neither new in our industry nor unexpected in an emerging field; these challenges should therefore not prevent others from moving forward.
The Benefits of Reciprocal Mentoring in the Oil and Gas Industry
Authors: Dalrymple Lori R. , Dalrymple Eldon D. 
Published: October 2018

Abstract

Objective/Scope
As the Oil and Gas industry looks for ways to better manage its increasingly age diverse workforce, reciprocal mentoring (RM) has become a necessity. Industry veterans are nearing retirement. Young entrants to the workforce are knowledgeable in technology, but lack industry experience. These two circumstances, along with other factors, helped create the perfect storm – the Great Crew Change.
RM can pave the way for a new standard of open dialogue in business, stretching far beyond technology. Ideally, learning and information sharing would cross all lines of seniority and responsibility.

Methods, Procedures, Process
Everyone knows that mentoring can be useful to a young employee. However, there is a lot that junior employees (millennials) can offer as mentors themselves. Senior employees were trained when technology transfer was slower and less sophisticated. They learned to give presentations without the aid of PowerPoint and other media available today. Often, they relied on a flipchart for a presentation, so they have well developed soft skills and interpersonal skills. Millennials recently graduated, have more experience in technology transfer, and recent applications and technology developed, and are more inclined to communicate through email, text, and social media. RM acts as a powerful tool to help both junior and senior employees strengthen specific skills.

Results, Observations, Conclusions
Reciprocal mentoring can create dynamic teams utilizing the overall strengths of both millennials and senior employees. These two-way conversations become avenues where employees can discuss insights from both perspectives and gain valuable knowledge from one another in an environment of trust. With the increasing number of Millennials joining the workforce in the oil and gas industry, management must incorporate new ways of mentoring them. The increase in the age gap between senior employees and millennials creates a challenge to keep the workforce engaged.

Novel/Additive Information
Differences in perspective, attitude towards work and different motivation can result in friction and an unwillingness to collaborate. This is the role of reverse mentoring which is detailed in this paper. With the "Big Crew Change" we are experiencing a shortage of younger more experienced technical professionals. Reciprocal mentoring is a way to bridge that gap.