bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Protection Strategy and a High Performance Drill-In Fluid for Deepwater Wells in the South China Sea
Authors: Zhao Xin , Qiu Zhengsong , Wang Mingliang , Liu Yunfeng , Chen Ganghua , Liu Shujie , Zhou Jianliang , Xing Xijin 
Published: August 2016

AbstractThe protection of high porosity and high permeability reservoirs has not got enough attentions because the excellent hydrocarbon storage capacity would provide high oil and gas productivity even being damaged to some extent. Deepwater oil and gas reservoirs are mainly high porosity and permeability reservoirs, and the reservoir protection is important because severe reservoir damage will cause an enormous economic loss due to high investment and risk of deepwater operation. A new deepwater gas field in the western part of the South China Sea must be developed soon, and the reservoir protection strategy needs to be studied.The characteristics of the reservoir were studied by X-ray diffraction, scanning electron microscope, mercury intrusion porosimetry, hot rolling dispersion test and liner swelling test. Furthermore, the water and salinity sensitivities of the reservoir were studied. The results show that the reservoir has high porosity and high permeability with an average porosity larger than 30% and an average permeability higher than 500×10-3 μm. The large pore throats will be easily invaded and plugged by solids in drilling and completion fluid. Therefore, effective temporary-plugging of the pore throats with a wide size range is extremely important. The content of clay mineral is 9% to 19% with approximately 50% mixed-layer illite-smectite, presenting potential borehole instability and reservoir damage risk due to its strong hydration ability. In addition, the reservoir has strong salinity sensitivity and medium-weak water sensitivity. The reservoir protection strategy of drilling and completion fluid related to the properties of the reservoir was proposed. A multi-stage bridge temporary-plugging method was used to prevent the invasion of solids into the pore throats with a wide size range. A highly inhibitive polyamine was selected to inhibit the hydration of clays to maintain wellbore stability and reduce reservoir damage. Because of the requirement of gas hydrate inhibition and density adjustment, a high performance water-based drill-in fluid with formate brines was developed. It has excellent reservoir protection performance with the permeability recovery rate approximately 90%. Meanwhile, it performs well in inhibiting clay hydration, hydrate formation, and has good rheological as well as filtration properties over a wide temperature range from 4 °C to 75 °C.This work provides theoretical guidance of reservoir protection and a high performance drill-in fluid for the target deepwater gas filed. We hope it will also be useful for the protection of high porosity and high permeability reservoir in other deepwater oil and gas fields.
Investigating the Influence of ESP on Wellbore Temperature, Pressure, Annular Pressure Buildup, and Wellbore Integrity
Authors: Kang Yongfeng , Liu Zhengchun , Gonzales Adolfo , Samuel Robello 
Published: August 2016

Abstract
The electrical submersible pump’s (ESP) impact on wellbore temperatures and integrity is seldom discussed in literature. Most literature discusses ESP run life and failure. The ESP heat dissipation increases the wellbore temperatures. Therefore, direct and indirect thermal-induced stresses are applied to the casings and tubing. At the same time, the trapped annular pressure buildup (APB) also increases, thereby applying additional stress on the casings and tubing. This raises the question—is the safety factor still valid? This is crucial in high-temperature/high-pressure (HT/HP) and deepwater/ultra-deepwater wells that have narrow design margins.
This paper presents studies on the prediction of wellbore temperature and pressure profiles, which account for the ESP heat dissipation effect on APB. The heat dissipation from the ESP electric motor, pump, and cable are considered. Then, the convective and conductive heat transfer through the wellbore are described in a transient wellbore temperature model. The updated temperature profile is then applied, and the APB and tubular stress analysis is revisited.
The model is integrated into an advanced casing and tubing design software platform. Case study results show increasing temperatures along the wellbore. The increased temperatures induce the APB and the strings axial compressive stress increase. In the studied case, the APB increased up to 23.6%. The increased APB induced additional loads on the tubing and casings, which can result in collapse/burst failures. Both theoretical analysis and case studies show that if the original design did not consider the use of ESP, induced APB can cause casing/tubing failure and result in wellbore integrity issues.
The findings indicate ESP heat dissipation does affect the wellbore integrity. Attention should be paid to the possible allocation of ESP in the future to achieve an accurate APB prediction during the modern wellbore completion design and planning phase. The findings are of particular interest in production monitoring and control, wellbore completion, ESP selection, casing/tubing design, and wellbore integrity, especially for mature-field and offshore wells.
Modeling and Simulation of Annular Pressure Buildup APB Management Using Syntactic Foam in HP/HT Deepwater Wells
Authors: Liu Zhengchun , Samuel Robello , Gonzales Adolfo , Kang Yongfeng 
Published: August 2016

Abstract
Annular pressure buildup (APB) in high-pressure/high-temperature (HP/HT) deepwater wells can result in wellbore failure, even during drill-ahead operations. Manufactured to collapse at a specific pressure and installed on the external casing wall, syntactic foam is an economical solution to mitigate APB and protect casing strings in offshore HP/HT wells. This paper focuses on the modeling and simulation of the effects of syntactic foam deformation on APB in casing/tubing annuli.
Syntactic foam is a composite material synthesized by filling a polymer, metal, or ceramic matrix with hollow glass microspheres (HGMSs). Under increasing hydrostatic pressure (HCP), the behavior of the foam material can be described using a HCP-strain curve typically consisting of three regions: linear elastic, plateau, and densification. A multisection linear model was established to express the volumetric strain vs. HCP relationship, which significantly simplifies the APB calculation while still ensuring sufficient accuracy. Analytical correlations were developed for the elastic compressibility and collapse pressure vs. temperature, which can generate feed-in data for the multisection linear model when only limited datasets are available.
A workflow was developed for the simulation of syntactic foam effects on APB in HP/HT wells. The syntactic foam models were implemented and integrated into a commercial casing and tubing design software platform. In a simplified example well, numerical simulation results were found to be consistent with the results from analytical calculation. In a case study of an offshore HP/HT well, numerical simulation demonstrates that syntactic foam is a viable and effective option for APB management. Combined with thermal flow and APB simulators, the implementation of the syntactic foam models enables more accurate casing/tubing load analyses. APB simulation including the effects of syntactic foam can provide valuable information to assist well design engineers in the design of HP/HT deepwater wells with long-term well integrity.
Finite Element Modeling to Determine Perforating Gun Collapse Failure Modes and an Engineered Solution
Authors: Craddock G. G. , Wight Jim , Harive Kevin 
Published: August 2016

Abstract
Three-dimensional (3D) finite element analysis (FEA)-based shock software is the next step in downhole shock modeling. This software uses a finite element and a fluid tool that simulates gun behavior on gun strings and adjoining tools, including perforation and subsequent stress conditions. By examining temporal stress predictions at element locations, failures can be estimated based on these numbers. On a recent perforating operation, there was an undesired event that resulted in a collapse of the spacer section within the perforating string. The event flattened spacers, but did not ruptured them, resulting in not damage to other sections. This event highlights how localized dynamic forces could be over looked in the present 1D industry dynamic modeling software. As part of the planning process, the current industry standard shock software was used to simulate the string and predict the likelihood of failure. The models showed no failure flags; additionally, post-operation models did not predict the downhole events that occurred. As part of the investigation into the events, this modeling shock software was used to provide a more detailed model of the event. These models provide a full 3D representation of the string and allow a much more detailed understanding of the pressures and stresses during the perforating event. The models clearly showed the string design was not optimized for the localized dynamic event and there was a risk of collapse. Pressures were plotted as a function of time at locations on the outside of the spacers, safety spacer, and loaded guns. The results showed pressures outside the spacers, which exceeded static threshold values and lasted for extended durations. Other regions, such as the safety spacer, did not show this effect at above static threshold magnitudes. As well as being able to reproduce the collapse event , work was taken a step further to examine mitigation designs that could be used to help prevent these types of issues. It was possible to test several of these designs using the 3D FEA-based shock software to validate their functionality.
Overcoming the Challenges of Running Large Diameter Casing Through High Inclination Wellbores at Shallow Depths in Deep Water Wells
Authors: Mitchell Sarah , Reagins Deandre 
Published: August 2016

Abstract
Historically, running large diameter surface and intermediate casing in the shallow sections of a well with a high build rate and inclination has proven to be very challenging, with a high risk of getting stuck off bottom. At the same time, with limited drilling margins, it has become important to be able to successfully set large diameter casing under these conditions to enable the well to reach target objectives and/or avoid subsurface hazards.
A comprehensive analysis reveals that a major contributing factor to the difficulty of running large diameter casing is due to the large end loads resulting from the high inherent stiffness of the casing as it is bent through dog-legs or ledges. Finite element analysis indicated that these forces were high enough to cause the shoe to dig in to softer formations, and that the end forces increased substantially as casing size and weight increased, or as dog-leg severity and inclination increased.
A fairly simple solution was identified: a composite flexible shoe run at the bottom of the casing reduced the side loads at the bottom of the casing when running into the hole. Effective communication and cooperation between designer and operator allowed for a product that was thoroughly tested and examined from an operational standpoint to identify risks and address possible failure modes. Smaller tools were also proven out in higher build rate horizontal wells prior to running in a higher cost deepwater environment.
Several case histories are presented that demonstrate the ability to run 18, 16, and 14-inch casing smoothly to target depth through build sections with doglegs of more than 4°/100ft, in soft formations, and to inclinations of more than 60° using a composite flexible casing shoe.
The ability to reliably set large diameter casing through build sections and into high inclination wellbores expands the envelope of design possibility when planning deepwater wells.
First Deepwater MPD Operation in the Gulf of Mexico: Challenges and Lessons Learned
Authors: Samuel Nishanth , Santos Helio , Valluri Sandeep 
Published: August 2016

Abstract
In the Gulf of Mexico, the Paleogene play presents challenges in narrow drilling margins. To overcome the challenges, a fully integrated Managed Pressure Drilling (MPD) packaged system was incorporated into a deepwater drill ship. The MPD system was designed to drill a deepwater, high pressure / high temperature well in the Gulf of Mexico. This paper will explain the lessons learned, the challenges and improvements carried out through the use of the MPD system in three key areas: advanced wellbore pressure modeling, downhole characteristics fingerprinting using downhole data and the MPD equipment. A full MPD system was designed to comply with all new government regulations and its performance proven through successful cased hole and open hole testing. Upon government approval, the new system was used to drill the well in full MPD conditions, where the mud weight (MW) was brought below pore pressure and the well was balanced with applied surface back pressure. Throughout the well, there were numerous lessons learned in three key areas: wellbore hydraulics modeling, downhole characteristics provided by PWD data, & the MPD equipment. An advanced wellbore pressure model was needed to accurately maintain the appropriate downhole pressure through the application of surface backpressure. The system used this model to perform simulations and applied the results of those simulations to control the surface equipment. Downhole Pressure While Drilling (PWD) data provided verification of the modeling results and applied surface back pressure as the well was drilled. Challenges faced during the operation included pressure compensation due to swab and surge as a result of pipe movement, and fluid inertia coupled with compressibility of the mud. The downhole characteristics of the well were tracked through PWD data, which was important in compensating the backpressure during connections and drilling. Further, the downhole data were consistently used to fine-tune and adjust the applied back pressure to ensure the well did not go underbalanced during these operations. Continuous improvement during operations also led to increased reliability of the MPD equipment.
Drilling Through Salt Formations: A Drilling Fluids Review
Authors: Amer A.. , Dearing H.. , Jones R.. , Sergiacomo M.. 
Published: August 2016

Abstract
In many deepwater plays around the world, salt formations overlie prolific reservoirs containing billions of barrels of oil. Drilling into these reservoirs requires the successful penetration of the challenging salt layers. Based on experiences in key deepwater basins, this paper reviews the fluids and techniques used to drill through salt formations.
Salt formations are unique. Salt has little porosity and permeability. It can flow plastically through other geological rock beds under stress with "salt creep" resulting in wellbore size reduction and casing collapse. Salt can also dissolve in water necessitating the salinity of a water-based fluid be kept near or at saturation to avoid or minimize wellbore enlargement that can lead to poor cementing of the casing and deficient zonal isolation.
In spite of the aforementioned issues, salt formations are drilled successfully around the world, and drilling fluids play a vital role in a successful drilling operation. A downhole simulator cell (DSC) has been found to be a key tool in assessing the effect of drilling fluids on salt formations by drilling salt cores at in-situ conditions of temperature and pressure while monitoring the core and fluid interactions.
This paper combines a downhole simulation cell (DSC) testing and data from previous literature to provide a comprehensive overview of drilling fluids interactions with salt formations. This dialogue combines the experiences of drilling salt as seen from a drilling fluids perspective into one publication.
Three generalized fluids are evaluated: riserless water-based fluid (WBF), high-performance water-based fluid (HPWBF), and synthetic-based fluid (SBF). Performance criteria used to evaluate fluids include rates of penetration (ROP), hole cleaning, wellbore stability and washout minimization. Environmental compliance and system strengths and limitations are outlined. Topics include evaporite mineral types and drilling challenges including exit strategies and tar beds.
The Development and Qualification of a Novel Proppant System to Enhance Performance of High Rate Soft Sand Water Injection Wells With Cased Hole Sand Control Completions
Authors: Whaley K.. , Rickman R.. , McClelland K.. , Decker T.. , Murillo R.. , Candella J.. , Roper T.. , Johnson D.. 
Published: August 2016

Abstract
With the rapid increase in number of major development projects in soft sand reservoirs in the last 20 years the industry has had to develop a range of sand control completion technologies to deliver high rate, reliable wells to support the production and injection. Sand control completion systems for production wells are generally mature and are broadly speaking typically successful. The development of reliable sand control systems for water injections wells has however typically proven to be significantly more challenging and this has impaired the economics of multiple projects by either necessitating the installation of more water injection wells, the periodic remedial repair of existing injection wells or suffer the inevitable impact on production rates and reserves recovery.
In many locations Cased Hole Fracpack (CHFP) or Gravel Pack (GP) completions have proven to have the capability to deliver high rate water injection wells. However, their long term reliability is often compromised due to the loss of the annular pack proppant when injecting water above formation fracture pressure. The loss of the annular pack proppant compromises the sand control system and reduced injection rates and formation fill in the wellbore typically soon follow.
In order to address this issue of annular proppant pack loss, a project was initiated to develop and qualify a proppant system that would remain immobile in the casing to screen annulus of CHFP/GP completions over life of well even when injecting water at high rate (in excess of 30,000 bbl/day) above formation fracture pressure.
Potential solutions from both inside and outside the oil and gas industry were reviewed and put through a rigorous program of lab based screening tests. Successful products progressed to the second stage qualification process of further lab scale and larger yard scale testing.
The final phase of the qualification process involved taking the preferred proppant product, a new generation resin coated proppant activated by a combination of a chemical activator additive in the fracturing fluid and temperature, and performing two onshore field trial operations which included several months of high rate water injection. The first installations of the new proppant product in deep water injection wells are expected from 2016 onwards.
One of the main challenges in the program was how to demonstrate suitability for both the installation process and life of well down hole service conditions in the lab and yard environment in a short time frame. This demanded the development and construction of a wide range of novel test procedures and apparatus. The results of this qualification and testing program will be discussed in this paper.
Physical and Mechanical Properties of Field-Generated Foam Cements: Implications for Cement Property Prediction and Modeling
Authors: Gieger Connor , Fazio James , Spaulding Richard , Kutchko Barbara , DeBruijn Gunnar 
Published: August 2016

Abstract
Properties of foam cement are of particular importance to the zonal isolation and mechanical integrity of wellbore cements used in offshore applications. This paper presents an assessment of physical and mechanical properties of field generated foam cements. These properties are measured to determine the performance of cements generated at field conditions, and for comparison with data sets obtained from laboratory-generated cement. These measured properties are also integral data for the development of empirical relationships used to estimate the properties of cements existing in the wellbore.
Measurements of mechanical properties include both dynamic and static testing methods. Dynamic testing of Young's modulus, Poisson's ratio, and other mechanical and physical properties are performed under cyclic effective pressures from 6 – 48 MPa. Dynamic measuring practices utilize ultrasonic velocity measurements at 4 MPa intervals during pressure cycling. Static methods perform strain measurements under uniaxial loading, and are used for strength analysis and comparison with dynamic measurement results. Laboratory-generated cements were mixed according to API-RP-10B-2 and 10B-4, using a Class H Portland cement system. Field-generated samples were obtained from industry collaborators.
Results indicate irreversible changes to permeability and Young's modulus over the course of pressure cycling. These systematic variations provide insight into how foam cement properties may be altered when exposed to pressure variations within the wellbore. Empirical relationships are developed between parameters such as compressive strength, permeability, porosity, p-wave velocity, and Young's modulus for foam cements using linear and non-linear least-squared regression analysis. Preliminary empirical relationships show strong associations between compressive strength and each of the various properties of interest. This is a promising development in efforts to predict the properties of in-situ cements.
This assessment of mechanical and physical properties of field-generated foam cement provides an in-depth look at cements generated at simulated in-situ pressure conditions. A comparison of field- and lab-generated cement properties provides information about how representative lab-generated cements are of typically-unavailable field samples. The empirical relationships reported in this study may help to provide, using the few measured properties of placed cements, a method of estimating physical and mechanical properties. This information is intended to aid cement design and wellbore planning for more reliable wellbores.