bluuebunny/crossref_metadata_2025 huggingface dataset:
CwD – Enables for Successful Extended Reach Drilling. First Time with 9 5/8" Casing at High Angle
Authors: Amar M. S. , Za'ba M. A. , Liew A.
Published: October 2018

State of the art technology provided by Casing-drilling Services has successfully delivered an Extended Reach Drilling well (ERD) under one of the most challenging scenarios. Challenge consisted on drilling the well from a triple-splitter wellhead in a Malaysian offshore field, navigate through a highly collision-prone platform, pass through a zone prone to loss circulation, and ultimately set up the casing as deep as possible to allow producing from the objective zones, which is located at adjacent fault block.

To enable this long ERD well, the surface casing must be set as deep as possible for higher chance of success in reaching reservoir objectives. The triple-splitter wellhead design with 13 3/8-in. conduit constrained the casing design to smaller casing design. The engineering framework and the drilling techniques had to be adapted to overcome the expected challenges. Analysis of the solutions developed during design and execution, the outcome of the solutions, and the learnings from the project have been documented.

The directional casing-drilling technique enables the surface hole to be drilled as deep as possible with a dynamic kill-while-drilling with a diverter in the event of any kick or shallow gas hazard. A feasibility study was performed during which all the key hazards from anti-collision in this highly congested platform, offset well losses, and well control issues were collected and mapped. After numerous engagements with industry expert/SMEs from both the operator and service providers, casing-drilling technology was selected based on lowest risk and highest chance of success. Strong collaboration at early planning stages was vital in this scenario where all the existing casing-drilling techniques and operational practices were challenged.

The execution result was highly successful. This was the first application of directional casing-drilling from a triple-splitter wellhead with polycrystalline diamond compact (PDC) bit. The PDC bit has allowed significant increase in weight on bit (WOB) and subsequently an increase in rate of penetration (ROP), which is comparable to conventional drilling. In addition, the casing-drilling service eliminates the need to drill a pilot hole where dynamic kill is not possible. This case study provides guidelines, from the planning work to successful field execution, that can be applied for ERD well design.
High Challenging Tight Oil Development by Integrating Innovative Reservoir Boundary Detection Technology into High Efficiency Horizontal Drilling Campaign in West China
Authors: Zhang Jiafeng , Zhi Chennai , Zhu Jianxin , Ye Yiping , Li Tong , Wang Fei , Wang Yong , Li Shuzhong
Published: October 2018

In West China, MH field is typically featured with complex high challenging unconventional reservoir. Very tight conglomerate lithology composed of volcanic rock, claystone and limestone cement as the matrix with average porosity of 9.6% and average permeability of 0.96md. The buried depth of target reservoir is around 3180m. The oil production of vertical well is about 5~6t/day after stimulation (fracturing) while horizontal well production is more desirable and about 3-4 times of vertical wells.

However, the operator faced much high challenges in horizontal drilling such as unstable long open hole interval, extremely slow rate of penetration (about ~3m/hour) in abrasive, grinding conglomerate and shale cap rock (less than 1m/hour). Reservoir structural and stratigraphic uncertainty such as local formation dip changes, 3-5m thick tight sand stacked or pinch out, inconsistent shale inter-beds and oil pay lateral variations often result in unexpected exits from target pay. In current industrial downturn, XOC (Xin Jiang Oil Company) is never so urgent in pursuit of a cost-effective way to secure high efficiency horizontal drilling campaign and successful development of this kind of unconventional tight reservoir.

A pilot project of 6 horizontal wells drilling campaign was launched. The result shows that conventional drilling and measuring while drilling technology like Motor plus GR only was not adequate to address the drilling issues, improve drilling efficiency and achieve the horizontal Net-to-Gross (reservoir exposure rate) objective. However, since the latest high DLS (Dogleg Severity) RSS (rotatory steerable system) drilling technology and unique boundary mapping technology was introduced to XOC and applied in 2016, the drill efficiency and well placement NTG was significantly improved. Boundary mapping technology realized proactive real time geo-steer the wellbore to stay in target sweet spot by detecting reservoir top/bottom at 2-4m TVD away. It significantly increases space for timely decision-making and avoid unplanned exiting from target zone. The newly developed hybrid RSS drilling technology can provide as high DLS as 17degree/100feet and ensure smooth hole in a fully rotate fast-drilling way. The first batch drilling of 10 wells was completed with above technology application, horizontal section ROP increase 47.8%~103% and average footage per run increase 49.1%~59.1%.

With the success of the first 10 wells, XOC decided to extend the employment to whole MH field which will have more than 55 horizontal wells. This paper will delineate the technology application optimization through some distinctive case studies.
Rig Time Optimization and Risk Mitigation Utilizing Through Drillpipe Logging Technique with Slim Wireline Logging Suite
Authors: Ngo H. , Chommali P. , Charucharana T. , Rattanachan S. , Ung-Aram K. , Tangkaprasert P. , Thiangtham C. , Pinprayong V.
Published: October 2018

The Sirikit field is a mature reservoir located in the Phitsanulok Basin in north-central Thailand. The field produced first oil in late 1981. Typical logging programs include a complete set of openhole (OH) logging suites such as a triple combo, including gamma ray-neutron-density-resistivity, or quad combo including gamma ray-neutron-density-sonic-resistivity. The reservoir production and injection are carried out with commingled completion. Therefore, wireline formation testing, and sampling tools are usually included for acquisition.

Development wells with highly deviated trajectories pose challenges to conventional wireline logging (WL) operations, especially in deep wells exceeding 3,000m. In sections with high dogleg severity, the tools are prone to sticking, and the cable can become key-seated due to hole conditions, deviation, washouts or caving.

Log data is a vital component for studying geological complexity, completion and production planning. Therefore, there is a need for an alternative method to convey WL tools to reach the bottom of the hole. In 2015, an alternative conveyance method called "through drillpipe logging" (TDL) was proposed to mitigate the risk of WL tools sticking or hanging up in an openhole environment. This method uses a slim-chassis, 2.25 in. outer diameter (OD), WL logging suite that enables the tool to be run through the drillpipe. The first TDL job was trialed in Thailand in May, 2016 as the second run after the WL run hung up. This TDL run hosted a full triple-combo suite and WL formation testing tools, which reached total depth (TD) while overcoming hole-condition issues that had been experienced during the first run. Following this successful log run, the TDL has become the preferred contingency planning option to support WL operations in challenging wells. To date, a total of 64 jobs, including triple combo (TC), quad combo (QC), formation testing & sampling (FTS) and cross-dipole sonic (CDS) have been executed successfully with less operating time than conventional contingency processes involving wiper trips, tool pushing, or pipe conveyed logging. This track record confirms that TDL provides a fit-for-purpose solution for logging in challenging conditions.
Performance Improvement from Drilling Control Systems Alarm Management and Analytics
Authors: Goetz Christopher
Published: October 2018

Control Systems Alarms on offshore rigs are inarguably poorly designed. Drilling Control Alarms Systems (DCAS) in particular, are notorious and the pack leaving much to be desired. Excessive alarm volumes on these Integrated Control Systems (ICS) lead to Driller alarm blindness and exceed all industry recognized standards. The problem is exacerbated by the general lack of a Human Machine Interface (HMI) console dedicated to the maintenance crews or other roles to leverage for equipment insight and preventative maintenance.

Because of these conditions, Drillers are inundated, and critical alarms are often ignored. Maintenance crews are reactive, resulting in missed preventative maintenance opportunities and equipment failure or non-productive time (NPT). The result is a general opinion that these DCAS are poorly designed, and the alarms themselves are not useful.

This paper will work to alter that perception through illustrating that the DCAS do indeed contain useful information if examined with the correct lens. Additionally, this paper shows that Drilling Contractors have the tools at their disposal to leverage this lens on any ICS. It will illustrate how that can be done, as well as discuss some of the best practices that Drilling Contractors ought to adopt to improve the capabilities of their DCAS.
Achieving Performance Excellence Through Integrated Efficiency Workflow Services
Authors: Soong A. , Arriffin M. F. , Rosland H. A. , Ismail B.
Published: October 2018

Issues emerged from complications with multiple sources of information, including (but not limited to) time taken to complete an entire well, costs involved, and potential risks that can disrupt the duration necessary to analyze offset wells for field development planning. Currently, there is an absence or a less visible workflow or informational standardization because different divisions and field teams work on silo-based knowledge and procedures. To make matters worse, sufficient data are being logged and stored in servers without being used in constructive ways.

This paper discusses a solution that helps save time and regulate standard operating procedures (SOPs) when planning well authorizations for expenditures (AFEs) using actual stored well data, particularly during field development planning. The solution reviewed in this paper can also assist the operation team when reviewing and help improve rig operation performance, such as drilling and pipe tripping, by comparing processed data for rig vs. rig, well vs. well, or field vs. field, whichever end users desire. Additionally, it can statistically map out potential risks and visible/invisible nonproductive time (NPT). Existing server data can then be reviewed to help ensure stakeholders make calculated decisions based on quality data.
Innovative and Cost-Effective Invert-Emulsion Fluids for Drilling Complex Wells
Authors: Al-Bagoury M. , Revil P.
Published: October 2018

Formation losses, high torque and drag, managing equivalent circulating density (ECD) and barite sag are some of the most frequent challenges operators face while drilling complex wells such as deep water, extended reach or narrow pressure margin wells.

Invert-emulsion fluids are used to alleviate these challenges. However, the design of invert-emulsion fluids needs to be tailored to overcome specific drilling challenges. This paper describes the design of invert-emulsion fluids using synthetic base oils such as MG3 DF, Sarapar 147, Saraline 185V and EDC 99 DW and weighted with micronized ilmenite to densities up to 2.30 sg (19.2 ppg) and temperatures up to 232°C (450°F) to handle such challenges. These fluids show the ability of micronized ilmenite to provide significantly lower rheologies to control ECD, significantly reduced sag potential and lowered formation damage. Formation damage potential was assessed using high and low permeability sandstone formation cores.

Ilmenite is acid soluble and easy to remediate if required. The acid solubility of ilmenite will also assist in freeing stuck pipe, which is not the case with barite weighted systems.

Fluids with micronized ilmenite have been effective in obviating drilling challenges. This paper presents designs for high-density, cost-efficient fluids weighted with micronized ilmenite for the drilling of challenging wells. This fluid was used to drill and complete 14 ERD wells with measured depths of >36,000 ft. Utilization of this reservoir drilling fluid has contributed to increased reservoir contact, improved productivity and provided a reduction in non-productive time (NPT).
Egina Deep Water Project Completion Success: One Team Working Together Setting New Performance Standards
Authors: Johnson Kenneth , Morand Christophe , Williams Mark , Okengwu Victor , Akinniyi Temitope , Chaloupka Vladimir , Djenani Romain , Okpalla Chinedu , Bassey Unwana
Published: October 2018

A service company was challenged to deliver best-in-class upper and lower completions by leveraging deep water completion experiences throughout West Africa with the operator and service company's global best practices and lessons learnt. An operator reduced lower completion times, standalone screens, and open hole gravel packs by 60% between the 1st and 24th well while reducing upper completion times by 40% for the same wells. Well construction durations, including drilling and completion, currently averages 24 days per well, with lower and upper completion operating efficiencies and run reliabilities exceeding 97%.
Production has Spoken, Listen to Your Reservoir Needs and Technology Respond - A Case Study of SS Field Development
Authors: Zakariah A. , Rosland E. A. , Afandi T. , Goh K. G.
Published: October 2018

SS Field with its longer production data now available has enabled further validation of the previous assessment (i.e. SPE-17005 by N. Noridah et all, 2013) of the reservoir needs and technology respond in this field to-date. This paper also highlights the effectiveness of the field-wide downhole flow control solution in terms of more oil and managing undesired field water-cut. It is scrutinized based on the actual field Ultimate Recovery (UR) versus the predicted recovery to further optimise recovery in infills plan.

Extensive evaluation on production performance was conducted well-by-well to engage the overall field performance. The actual production performances are clustered in the categories from the ‘underperformers’ to the excellent producers, considering the reservoir attributes such as reservoir characterization, geological understanding and contacts movement. Meanwhile, technology responds in terms of zonal control efficiency across the sandface is analyzed for improved comingled oil production multi-zones. The assessment is further applied in the infill well-creaming for the extended development plan in SS field.

The study correlates the best reservoir attributes to the technology respond in order to maximize future infill recovery in ensuring fit-for-purpose implementation. Years of production experience have demonstrated a consistently better recovery of SS field against the expected FDP. 75% of the producer meet the FDP production target which contributes towards overall field > 25% EUR despite only near the half of the production life (~20 years).

SS Field is the first pilot PETRONAS field applying field-wide downhole flow control (12 wells) and intelligent Completions (2 wells). An integrated evaluation of the production performance in this field with subsurface understanding is paramount for technology replication. It is a case study that serves as a benchmark for development decision in other fields with similar reservoir characteristics. It also serves as best-practices and lesson-learnt to provide a better insight of a downhole flow control solution efficiency in the late-production strategy of suppressing water for further production enhancement via EOR / infills.
Achieving Repeatability and Reproducibility in Competency-Based Training
Authors: Lau Hon Chung , Pang Michael
Published: October 2018

In today's high-stakes E&P operating environment, achieving operational excellence is key not only to profitability but also obtaining a license to operate. Doing so requires E&P companies to have competent staff who are qualified to perform their jobs professionally at all levels of seniority. As technology and the regulatory environment change, continuous education for technical professionals is not only desirable but necessary. Competency-based training (CBT) is one of the most effective ways to ensure competency development in E&P professionals. Unlike traditional training, CBT focuses on helping the learner to master well-defined job-related competencies. The hallmarks of CBT are repeatability and reproducibility of results. Repeatability is the ability of the same learner to achieve consistent results whereas reproducibility is the ability of multiple learners to achieve the same consistent results. This paper discusses the ten elements of CBT in order to achieve repeatability and reproducibility.
Casing Drilling Technology as the Solution for Severe Lost Circulation: LSE Casing Drilling Pilot Project Case Study
Authors: Abdila Sayid Faisal , Harahap Andy Mahyuni , Yuristyanto Haryo , Muslim Aziz , Noviasta Bonar , Falhum Hanafi Muhamad , Astasari Kanya
Published: October 2018

The Louise (LSE) is one of the primary oil-producing fields in the Pertamina EP Asset V. This area has an issue with high potential of total losses in the top section [~400 m measured depth (MD)], which causes an inability to set the 13.375-in. casing at the required depth. As a result, this problematic zone must be drilled conventionally in two different sections, 17.5 in. and 12 .25 in., whilst combating losses. Pertamina EP spent up to 10 days as nonproductive time (NPT) to combat losses, resulting in high investment cost. A new innovative method was required to face this challenge with the objective of drilling deeper through the loss zone in a single run in a more effective and efficient and a safer way.

Nondirectional casing drilling technology was introduced to solve this problem. The casing drilling system simultaneously drills and runs the casing through the lost circulation zone in a single run, which provides a more efficient and a safer operation. Its plastering effect helps strengthen the wellbore by smearing cuttings into the wellbore wall, sealing pores in the formation to reduce fluid loss. At the same time, it saves the rig operating days by eliminating the loss-combating days and the dedicated casing run. The key driver of this technology is the drillable alloy casing bit specially made for drilling vertical or tangential wells, which can be drilled out by any standard PDC or milled tooth after it has drilled to total depth (TD) and the casing has been cemented in place.

On the pilot casing drilling project well, this system successfully drilled 351.25 m of 13.375-in. × 17.5-in. section to the casing point in a single run passing through the problematic loss zone. The 13.375-in. casing was cemented in place, and the casing bit was successfully drilled out using a conventional 12.25-in. PDC bit. Compared to the conventionally drilled offset wells, this technology enabled up to 220 m deeper 13.375-in. casing setting depth, which consequently eliminated the necessity of loss-combating activity in the 12.25-in. hole section.

The implementation of the casing drilling system solved the lost circulation problem and provided an additional benefit of eliminating a dedicated casing run. The casing drilling technology helped Pertamina EP to reduce the well drilling time by up to 4.75 operating days, saved up to USD 555,913 of drilling cost, and achieved 50 m deeper well TD compared to the plan. The pre-execution engineering work was one of the key activities leading to the success.
Development of Modified Rhizophora spp. Tannin Biopolymer Additive in Drilling Fluid System for High Temperature Well Applications
Authors: Ghazali Nurul Aimi , Naganawa Shigemi , Masuda Yoshihiro
Published: October 2018

The main objective of the current work is to investigate the performance of Rhizophora spp. tannin-lignosulfonate (RTLS) as a deflocculant in water-based drilling fluid (WBDF). Rhizophora spp. tannin (RT) was extracted from the barks, waste of conventional charcoal production. RTLS was synthesized and characterized by using Fourie transform infrared spectrometer (FT-IR) over a wide range of wavelength from 400 to 4000 cm−1 to determine the main functional group, and using thermogravimetric analysis (TGA) with the temperature range from 25 to 600°C to evaluate the thermal properties. Rheological properties of WBDF with the addition of RTLS as deflocculant were analyzed at room temperature condition and compared with industrial chrome-based deflocculant. The TG analysis revealed that RTLS has good thermal stability because the degradation temperature was observed at approxmately 280°C. The rheological properties demonstrated the yield point and the gel strength were reduced by addition of RTLS that indicated an improvement of the rheological performance. However, the trends for plastic viscosity showed a fluctuation with increasing in RTLS concentration because of the addition of suspended solid component in WBDF.
Overcoming the Challenges During Cementing Spacer Design for Deep Deviated HPHT Wells Containing Heavy Oil Based Muds
Authors: Brandl Andreas , Doan Angela Anh , Alegria Adriana Estela
Published: October 2018

Insufficient wellbore cleaning prior the cementing job is considered to be the biggest single factor leading to poor zonal isolation results. A mud-spacer-cement program with suitable fluid needs to be carefully engineered for the given wellbore conditions to improve cementing quality. We discuss optimum spacer design features which are critical for the successful cementation of deep deviated HPHT wells containing heavy oil based muds and review a simulated scenario. Advanced lab test methodologies beyond industry standards are utilized to model more accurately the given complex downhole conditions.

A simulated >20,000 ft highly deviated wellbore was characterized by HPHT bottomhole conditions and the rheological performance of the cement spacer was critical to job success. The well needed a stable cement spacer that would not settle-out on the low side of the >14,000 ft horizontal section, which would potentially put the well at risk. The 16.17 ppg mud required an even higher-density spacer system to clean it effectively. But conventional high-density spacer systems only compound the settling challenge and the well's anticipated bottomhole temperature of 350°F was expected to compromise any additives that might stabilize the fluid systems. Therefore a lab study about spacer stability was performed using a HPHT rheometer and the dynamic settling test – an industry standard which was actually established for cement slurries but not for spacer fluids. We found that a conventional spacer failed at 350°F by showing a rapid decline in rheology to almost zero viscosity and severe settling. To overcome the settling issue, provide stability, and maintain a sufficiently high rheology profile at given 350°F, we re-designed the spacer by using a modified biopolymer which shows a delayed hydration and viscosification over time successfully counteracting the destructive thermal effects.

The mud-spacer-cement fluid train was eventually optimized showing good fluid compatibility and maintaining within the narrow, 1.6 ppg margin that separated the pore pressure from the fracture gradient. The cementing job was designed using an advanced fluid displacement software, which predicted high mud removal efficiency under these challenging conditions. In order to enable proper mud displacement, the Friction Hierarchy—a key design factor that is often difficult to achieve under the extreme HPHT well conditions—was achieved with the new spacer concept.
Innovative Solution for High Temperature High Gas Rate Carbonate Well
Authors: Rashid Noor Hidayah , Fabian Oka , Johari M Raimi , Rosato Miguel , Samuel Orient Balbir , Idris M Faisal , Hong Ong Swee , Shaedin Muhamad Ridzuan , Loon Kweh Wei
Published: October 2018

Completing an over-pressured N field carbonate reef pinnacle gas reservoir with temperature above 170°C and relatively high concentration of CO2 and H2S can be tough. It gets tougher when in a high rate gas production, and the completion operation is managed in total losses condition. This paper presents the challenges, solutions and hindsight views of completion of high temperature high gas rate carbonate well with PMCD Top Kill Method via deployment of dual 7" and 4-1/2" liner string which are successfully accomplished in all 5 wells.
Learning from Experience: Real-Time H2S Monitoring System Using Fuzzy ART Unsupervised Learning
Authors: Alkamil Ethar H. , Abbas Ahmed K. , Flori Ralph , Silva Leonardo Enzo , Wunsch Donald C. , Chumkratoke Chatetha
Published: October 2018

Drilling boreholes through hydrogen sulfide (H2S) bearing formations such as Umm Er Radhuma and Tayarat Formations poses a critical challenge for the oil and gas industry in southern Iraq. In this era of increased concern for personal safety and environmental factors, the industry needs additional tools and methods for handling this deadly and corrosive gas. This paper describes how actual formation field data is entered into unsupervised learning software to train a H2S monitoring simulator to improve the drilling operators’ ability to detect H2S, analyse and then adjust mud pH to neutralize free H2S present in drilling fluids.

The H2S concentration measurements for five drilled wells in the Umm Er Radhuma and Tayarat fields in the South of Iraq used in a previous study are extended to include data from an additional 12 wells with 22 H2S events. This paper describes a real-time H2S simulator which consists of a computer interface kit implementing MATLAB code. The kit is provided with three LEDs (green, yellow, and red) representing different alert levels. The system monitors changes in H2S levels and triggers alarms depending on the levels. The setup of the alert levels for the simulator are adopted from both Health Safety Environment (HSE) policy and unsupervised vector quantization via Fuzzy Adaptive Resonance Theory (ART) neural network category ranges.

Results show that using Fuzzy ART to train the H2S simulator alert levels based on formation data leads to a smarter and more sophisticated alert system compared to the typical HSE set of alerts. Specifically, the Fuzzy ART derived alerts enable earlier detection of H2S events, faster response to changing H2S levels, and it computes workers’ exposure over time to H2S, to prevent excessive accumulation of H2S in the respiratory system.

The system demonstrates a smarter and more robust method for reducing risks to drilling personnel, rig equipment, and the environment while drilling in areas with H2S hazards.
Complete MPD Rigs: Is This the Future?
Authors: Gedge Ben , Yaw Norman , Postel David , Mardon Jeff , Frohlich Herbert , Nguyen Bot Viet , Thanh Ban Nguyen , Hong Duc Vu , Barbee Brian , Santos Helio , Gouldin David
Published: October 2018

There has been a lot of discussion around rigs with some capability to perform Managed Pressure Drilling - MPD - operations, with rigs having different permanent equipment installed. But all the rigs, somehow, would all be classified as ready to perform MPD operations. In order to clarify a bit this subject, this paper clearlt differentiates rigs with some permanent equipment installed, but the specialized MPD equipment and service are still provided by a service company, which is herein called MPD-Capable-Rigs, from rigs which have installed all the equipment needed for MPD, and the drilling contractor is the one offering the service, which is called Complete-MPD-Rigs. The objective of the paper is to discuss and illustrate what is involved in preparing an offshore and even onshore Complete-MPD-Rig. The paper also discusses the evolution of MPD, initially provided by service companies, with equipment needed to be rigged up and down on rigs, all the way to current stage where drilling contractors are providing the service directly. To achieve this stage the drilling contractors are equipping their rigs with the full MPD package and providing the service directly to the operators.

The paper describes the evolution of equipment installed and owned by the rig, from a few lines in the very beginning to a complete packge today. The movement towards the drilling contractor owning and offering the MPD service started with the deepwater rigs, but evolved to onshore rigs also. Today, both onshore and offshore drilling contractors Complete-MPD-Rigs.

Some examples of rigs with partial equipment installed are provided, illustrating the evolution of what a rig would own, until the most recent onshore and offshore examples of Complete- MPD-Rigs. This is definetly the future as it simplifies not only contractual and legal aspects but also improves a lot the competency of the rig crew and significantly reduces the problems of communications during an MPD operation when the equipment is not owned and provided by the rig.
The First CT Fiber-Optic Digital Implementation in Asia Pacific to Support Real-Time Perforation Depth Correlations and Enhance Wellbore Cleanout Efficiency in Horizontal Well, Thailand
Authors: Thawatthukool Prasen , Toempromraj Wararit , Sompopsart Suwin , Lilaprathuang Pipat , Weeramethachai Deephrom , Kiatrabile Thanita , Krisadasima Supakorn , Wattanasuwankorn Reawat , Pathmanathan Indran , Kritsanaphak Kritsana , Kangsadarn Arweephan , Daohmareeyor Tuanangkoon , Bohorquez Jorge
Published: October 2018

An onshore operator in Thailand faced the challenges of placing bridge plug and perforations with 2-m accuracy in a horizontal multi-stage interval prior to a fracturing operation and efficiently cleaning out the sand from the wellbore after fracturing. The solution selected to solve these two challenges was a fiber-optic-enabled coiled tubing (CT) string to support real-time plug set / perforation accuracy and sand cleanout, the first of this kind of operation in the Asia-Pacific region.

A fiber-optic cable was carefully pre-installed for slack management inside the CT string before the CT was stabbed into the well. The fiber cable provided real-time telemetry from a casing collar locator (CCL) downhole tool to a digital data interrogator on the surface to gain more accuracy in the horizontal section. Once precisely positioned, the CT was pressurized to activate the hydraulic setting tools for plug set and activating the firing head for perforation guns fired at the exact target depth. Using CT deployment, the operator also avoided the gun moving upward and becoming stuck in the well, which is a risk with a wireline and tractor application. The fiber-optics application also enhanced wellbore cleanout efficiency after fracturing with the advantage of real-time downhole circulating pressure.

The application goals were achieved as planned for this project, proving that CT can be used in this horizontal well section in conjunction with fiber optics. The fiber-optic real-time digital data from the downhole tool provided more accurate depth measurements for placing plug set and perforations, as well as monitoring bottomhole pressure to control smooth sand cleanout in the wellbore. This application also helped minimize the risk of operational failures due to the perforation gun moving upward after firing and the risk of the downhole tool becoming stuck (because CT can have larger pulling capacity than electric line operations). This new application also proved to be cost effective because CT fiber-optics applications can perform both perforation and sand cleanout operations, eliminating the requirement for electric line and tractor on location, saving both time and costs.

The advantages and benefits of using the CT fiber-optic digital application for placing bridge plug, perforations, and sand cleanout in horizontal well completions have shown significant improvement in terms of operational efficiency, cost savings delivered to meet the well operator's budget, and safety supporting multistage fracturing zones.
Increased Run Life in Progressive Cavity Pumps from Characterization of High Nitrile Elastomers in the Orinoco Oil Belt
Authors: Han M. J. , Guerra E.. , Rangel S. V. , Gamez I. B. , Delgado A..
Published: October 2018

Progressive Cavity Pumping is the preferred artificial lift method in the extra heavy crude oil field Huyapari, located in the Venezuelan Orinoco belt. Typically, PCPs operating in saturated reservoirs such as Huyapari need to cope with significant amounts of free gas, often handling more than 50% of gas void fraction (GVF) at the pump intake. This, combined with production of large amounts of sand and exposure to aggressive fluids, poses vast challenges to the durability and performance of PCP elastomers. Consequently, a proper and engineered selection of elastomer materials has critical impact on overall pump run life.

This study describes a first experience in characterizing the effect of harsh fluids and solids on high acrylonitrile elastomers. Subject wells include those with high free gas and/or sand production rates, as well as those with elevated water cuts. The mechanical properties of elastomers were measured under controlled pressure and temperature conditions in order to define an optimum rotor-stator fit. Over 200 laboratory tests and several field experiments were conducted to allow for the most suitable selection of elastomer material regarding hardness and swelling behaviour. Aging tests and infrared spectroscopy were also used in these analyses to help reduce premature elastomer failures produced by hysteresis, explosive decompression and blistering. The results of the study indicate that PCP applications in wells producing high gas rates must avoid utilization of elastomers with a hardness below 65 shore A, because the increased gas permeability causes excessive swelling throughout the pump stator. In contrast, elastomers with hardness above 70-75 shore A proved to be more resistant to swelling and explosive decompression.

Benefits resulting from this study include an increased pump life cycle from 306 days in-hole in 2012 to 469 days in 2016. Premature PCP failure count decreased from 275 in 2012 (59% of wells in the field) to 153 in 2017.

Based on the results of this study, the authors propose new acceptance ranges for mechanical properties values (e.g. swelling performance and hardness) for PCP elastomer selection applied to extra heavy oil production in this field.
Analysis of Secondary and Tertiary High-Pressure Gas Injection at Different Miscibility Conditions: Mechanistic Study
Authors: Norouzi Hamidreza , Rostami Behzad , Khosravi Maryam , Afra Mohammad Javad
Published: October 2018

In the current survey, the time required to rupture the water film shielding the oil as a result of oil swelling caused by the diffusion of dissolved gas in the water phase and trapped oil behind it has been investigated in porous medium at high pressure and temperature. To study the active mechanisms, the experiments have been conducted with two different types of injectants: carbon dioxide (CO2) and methane (with different solubility in water), under different miscibility conditions at equal reduced pressures. Experimental observations have been interpreted using theoretical studies. Furthermore, the time of water-film rupture has been identified in production data and matched by an analytical model. This time and its monitoring during various gas-injectant types and regimes under reservoir conditions have not been previously addressed.

The results show that water film reduces the performance of oil recovery by limiting the interface of oil and gas phases. Under such a condition, the best scenario is miscible gas injection because the gas can effectively swell the oil and rupture the water shield. At miscible and near-miscible conditions, the time required to eliminate the water film increases as the injectant solubility in water decreases; however, there is a negligible difference at the immiscible regime. The trend of oil-recovery curves after rupture of the water film shows that oil swelling is one of the main mechanisms involved in water-trapped oil recovery. These results suggest practical guidelines to better understand the effect of the water-shielding phenomenon in the field of tertiary gas injection. The outcome of this integrated study could effectively increase the knowledge of shielded oil recovery using different gas-injectant types under various miscibility conditions and could prepare the required basis for compositional simulation of waterflooded oil production during tertiary gas injection.
Carbon Dioxide Induced Corrosion of Carbon Steel X65 Exposed to Nitrite Aqueous Solutions
Authors: Vargas Silvia M. , Woollam Richard , Durnie William , Hodges Michael
Published: October 2018

Nitrate used to control reservoir souring in oil fields contains nitrite impurities. Nitrite is a strong oxidizer, and when used in souring–treatment fluids, the flow path often includes carbon–steel piping. Vanadium, also an oxidizer, is at times found in oilfield–production streams that commingle with souring–treatment fluids. The interactions between nitrite and vanadium and their effects on carbon steel X65 corrosion were investigated.

The effect of nitrite on corrosion was investigated using synthetic brine to simulate produced water [rich in carbon dioxide (CO2), pH value of approximately 5] and seawater (negligible CO2, pH value of approximately 7). Tests were conducted with carbon steel X65 exposed to synthetic brine at 25, 60, and 80°C using a rotating cylinder electrode (RCE). The test results demonstrate the following:

The corrosivity of nitrite strongly depends on the pH level. Nitrite increases corrosion at pH of approximately 5 and is relatively benign at pH of approximately 7. Nitrite reduces to ammonium (thermodynamically stable in acid solutions), whereas vanadium(III) delays the formation of ammonium. Inhibited corrosion tests indicate that nitrite reduces the performance of the studied commercial corrosion inhibitors (CIs).
Particle-Transfer Between the Cyclone and Accumulator Sections of a Desander
Authors: Rawlins C. H.
Published: October 2018

The flooded-core solid/liquid hydrocyclone, also called a desander, is often used in the upstream oil and gas industry to separate particulate solids from produced water. A desander incorporates a solid/liquid cyclone with an accumulation chamber connected to the apex. Solids collect in the accumulator for intermittent removal while the overflow is discharged continuously. With a flooded-core and static-liquid volume in the accumulator, the trajectory of a sand particle from the cyclone inlet to the apex is changed, compared with that in an open underflow hydrocyclone classifier. In this project, the transfer of solids from the cyclone to the accumulator section is studied, with emphasis on the limiting flux. The settling of solids from the cyclone to the accumulator follows a turbulent, hindered-settling relationship that can be approximated by models used for sedimentation hoppers. Measurement of the apex-flux rate shows a maximum choke point, beyond which solids will back up into the cyclone section. The limiting inlet solids concentration to reach this choke point is ≈2 g/L for small-diameter desanders. An apex-flux balancing system is proposed to overcome this flux-rate limitation.
Effect of Natural Fractures on Wormhole-Propagation Behavior
Authors: Mou Jianye , Yu Xiaoshan , Wang Lei , Zhang Shicheng , Ma Xinfang , Lyu Xinrun
Published: October 2018

Natural fractures have significant influence on flow fields, thus affecting wormhole pattern in acidizing. This paper summarizes our research on wormholing behavior in naturally fractured carbonates. First, statistical natural-fracture models are established using the Monte Carlo method. Second, a two-scale continuum wormhole model is established to simulate wormhole propagation with natural fractures. Finally, extensive numerical simulation is conducted to investigate wormhole behavior and the effect of the natural-fracture parameters on wormhole pattern. In addition, possible wormhole-penetration distance is discussed. This study provides a theoretical basis for matrix-acidizing designs in naturally fractured carbonates.
On Subcool Control in the SAGD Producers—Part III: Efficiency of Subcool Trapping in the Nsolv Process
Authors: Irani Mazda , Gates Ian
Published: October 2018

Steam-assisted gravity drainage (SAGD) is currently the preferred thermal-recovery method used to produce bitumen from Athabasca deposits in Alberta, Canada. SAGD is, however, an energy-intensive process with large amounts of greenhouse-gas (GHG) emissions and required water treatment. One option to reduce emissions and water usage is with solvent-based techniques, such as the Nsolv™ process. Suncor and Nsolv have been working together on a bitumen-extraction solvent-technology (BEST) field demonstration at Suncor's Dover test site. The solvent-injection–produced-oil ratio (SvOR) is among the key performance indicators (KPIs) of the BEST facility. Solvent breakthrough caused by inefficiency of thermodynamic trapping, such as subcool trapping, contributes to SvOR and affects the facility's economic and artificial-lift efficiencies. Subcool is the temperature difference between the injected butane (at saturated condition) and produced fluids (mixture of butane condensate, upgraded bitumen, and formation water). One of the unknowns in this process is the efficiency of thermodynamic trapping. On the basis of field results, it is shown that, like the SAGD process, liquid-pool depletion presents a critical control on the performance of the recovery process. Although the produced fluids are depleted from the liquid pool at the base of the chamber, because liquid-butane viscosity dependency on temperature is not strong and its viscosity changes slightly with temperature, thermodynamic trapping (or subcool trapping) is not efficient. Stability analysis of BEST data suggests that vapor breakthrough is part of the process but can be minimized by operating at temperatures greater than the second subcool limit. The second subcool limit (or Nsolv optimal reservoir subcool) will vary over time, and it is shown to occur at slightly less than 4°C after liquid-pool development.
Thermal Effects of Liquid/Supercritical Carbon Dioxide Arising From Fluid Expansion in Fracturing
Authors: Li Xiaojiang , Li Gensheng , Yu Wei , Wang Haizhu , Sepehrnoori Kamy , Chen Zhiming , Sun He , Zhang Shikun
Published: October 2018

Liquid/supercritical carbon dioxide (L/SC-CO2) fracturing is an emerging technology for shale gas development because it can effectively overcome problems related to clay swelling and water scarcity. Recent applications show that L/SC-CO2 fracturing can induce variations in temperature. Understanding of this phenomenon is rudimentary and needs to be carefully addressed to improve the understanding of CO2 thermodynamic behavior, and thus helps to optimize CO2 fracturing in the field.

In this paper, we develop a numerical model to assess the impact of thermal effect on fracture initiation during CO2 fracturing. The model couples fluid flow and heat transfer in the fracture, and is verified by a peer-reviewed solution and observation in laboratory experiments. The velocity, pressure, and temperature are calculated at various time to demonstrate the thermodynamic behavior during fracture initiation. A pseudo shock wave is observed, associated with a compression wave and an expansion wave, which finally leads to an increase in temperature in the new fracture and a decrease in temperature in the initial fracture. The thermal stress is derived to investigate the difference between hydraulic fracturing and CO2 fracturing. The results show that thermal stress, resulting from CO2 fracturing initiation, is comparable to the rock strength, which will help induce microfractures, and thus promote the fracture complexity. The formation pressure after CO2 fracturing is also calculated to evaluate the pressure-buildup potential. This work highlights the importance of CO2 expansion during and after fracturing. It is one of the unique features that differs from hydraulic fracturing. For field-design recommendations, to enhance the thermal effect of CO2 fracturing, it is a good strategy to pump CO2 at high pressure and low temperature into the reservoirs with high Young's modulus, low Poisson's ratio, low permeability, and high geothermal temperature (or large depth).

This paper does not address the dynamics of fracture propagation under the influence of thermal effect. Rather, it intends to demonstrate the potential of the thermal effect of CO2 fluid in assisting the fracture propagation, and the importance of incorporating the compressibility of CO2 into fracture modeling and operation design. Failing to account for this thermal effect might underestimate the fracture complexity and stimulated reservoir volume.
Preformed Partial Gel Injection Chased by Low-Salinity Waterflooding in Fractured Carbonate Cores
Authors: Alhuraishawy Ali K. , Bai Baojun , Wei Mingzhen , Almansour Abdullah
Published: October 2018

Fractures and oil-wet conditions significantly limit oil recovery in carbonate reservoirs. Gel treatment has been applied in injector wells to modify the prevailing reservoir streamlines and significantly reduce fracture permeability, whereas low-salinity waterflooding has been applied experimentally to modify rock wettability toward water-wet for improved oil recovery. However, both processes have limitations that cannot be resolved using a single method. The objective of this study was to test whether low-salinity water could enable gel particles to move deeply into fractures to efficiently increase oil recovery and control water production. A semitransparent fracture model of carbonate cores and acrylic plates was built to study the effect of low-salinity waterflooding, fracture width, gel-injection volume, and fracture uniformity on oil recovery and to redirect the flow path to unswept zones. Preformed partial gel (PPG) and brine movements were visible through the model's transparent acrylic plate. Seawater was used for brine flooding and to prepare swollen particles; the seawater was diluted 100 times to create low-salinity water. A light crude oil was used, with 10-cp viscosity. Low-salinity water was injected after gel placement to test the gel-plugging efficiency. The results showed that the low-salinity water could improve gel propagation into the fracture and increase oil recovery because the gel strength (apparent viscosity) decreased as the brine concentration decreased. The gel-injection volume had a significant effect on the oil-recovery factor when seawater flooding followed the gel-injection process, although there was less of an effect when the gel was followed by low-salinity waterflooding. Moreover, the effect of low-salinity waterflooding on gel propagation decreased as the fracture width decreased. In addition, the resulting fracture uniformity illustrates a viable effect of the in-depth water-diversion treatment.