bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas-Assisted Gravity Drainage GAGD Huff n Puff Application for Fractured Basement Reservoir - Case Study
Authors: Dinh H. K. , Le N. V. , Peter M. G. , Nguyen V. T. , Dang T. S. , Nguyen V. Q. , Hoang N. D. , Truong T. A. , Tran H. M. , Nguyen K. B.
Published: October 2017

Gas injection methods such as Continuous Gas Injection, Water Alternating Gas and conventional Gas-Assisted Gravity Drainage (GAGD) have been widely used to improve/enhance oil recovery for conventional oil reservoirs. However, applications to naturally fractured basement reservoirs are still limited. This paper will introduce a case study of a new and effective GAGD method conducted in a Huff ‘n’ Puff fashion to improve oil recovery for a fractured basement reservoir in Cuu Long Basin, offshore Vietnam.

A GAGD pilot, which consists of 4 cycles, was conducted in which dry gas was periodically injected into an existing production well in an isolated area. It was expected that as the injected gas rose to the top to form a gas zone, it would push the Gas Oil Contact (GOC) downwards and might also push the Water Oil Contact (WOC) to the lower part of the producer or even away from the bottom of its wellbore. Before commencing the 4 cycles, gas injection, asphalting and reservoir simulation studies were conducted. In addition, a thorough forward plan was carefully devised before each cycle to determine possible effects of important operating parameters to the final outcome of that cycle.

From the results of the 4 cycles, it could be concluded that the gas injection volume is well correlated with cumulative water-free oil production, a parameter which indicates the effectiveness of the method in terms of the gravity-drainage mechanism. It could also be found that the final incremental oil gain of each cycle depended upon, not only, the gas injection volume, but also other important factors such as gas injection, shut-in time… suggesting that a non-linear optimization exercise is necessary to make the whole pilot economically successful.

The success of the GAGD pilot proves that it could be a simple and effective Improved Oil Recovery (IOR) method for fractured basement reservoirs. That can be a foundation for further application of the method to other reservoirs in the Cuu Long Basin.
First Open Hole Horizontal Near HP/HT Critical Sour Gas Wells Completion in Indonesia: Lesson Learned from BD Field Development Project in Kujung Formation
Authors: Nurdin M. S. , Etuhoko M. O. , McKen D. R. , Lian J.. , Syapari A.. , Nuryadi H.. , Fadil M.. , Utomo P. P.
Published: October 2017

BD is a near high pressure-high temperature (HPHT) critical sour gas field located in offshore Madura Strait in water depth of 152 ft. An exploration and appraisal well were drilled in 1987 and 1992 respectively, targeting BD reef at depth of 10,676ft SSTVD. Both well test results confirmed the limestone formation has characteristic of 305°F and 8,105 psi, with 5,000 ppm of H2S and 5.5% of CO2 content.

Four (4) development wells including three (3) horizontal and one (1) vertical well, were drilled to drain the reserves from BD field. The project was expected to deliver 120 MMSCFD of gas and 6,000 bpd of condensate for a period of 15 years production from BD field. Design, equipment and material to complete the well need to meet the target and be selected based on industry guidance and the environment to ensure the integrity of the well during the production time.

Completion for BD wells adapts multiple tie-back concept to provide consistent large flow area and big bore advantages, providing flexibility for future well intervention. It consists of 3 (three) main assemblies and was designed based on series of load cases to predict the completion reliability to withstand the load during the life of the well. During the installation, the assemblies were run in different batches and fluid environment.

Despite the challenges encountered during the preparation and installation, all wells were successfully completed and cleaned up safely without any incident. The completion could exceed the initial production target set by the reservoir engineering team.

This paper will discuss about the completion process from the first near HPHT sour field development project in Indonesia. It describes the design process, preparation and installation of the BD completion especially in the horizontal well. Challenges, basis of design, material selection, lessons learned and optimization taken to safely deliver the completion are also covered in this paper.
Low Field Cryoporometry NMR for Mesopores Distribution in Shale
Authors: Jin Xu , Wang Xiaoqi , Liu Xiaodan , Jiao Hang , Sun Liang , Su Ling , Bi Lina , Chen Yu
Published: October 2017

A large number of micro–nanopores constitute the main reservoir space of shale oil and gas reservoirs. To evaluate a reservoir pore throat system's structure, it is of great significance to quantitatively characterize the pore distribution. There are two commonly used methods for characterizing the pore structure: mercury intrusion and gas adsorption analysis. The mercury intrusion method is to determine the pore size distribution by measuring the amount of mercury in the pores under different external pressure. The detection range of this method is pores with diameters of 3 nm–400 μm, and the optimal detection range is pores with diameters of 100 nm–100 μm. The gas adsorption analysis method is to measure the adsorption amount of nitrogen and other gases at the liquid nitrogen temperature. the optimal detection range of this method is pores with diameters of 0.4–100 nm. Because of the complex structure of porous materials, the results of different experimental methods are inconsistent, and the pore structure information provided by a single method is limited. Since different porous solid materials have different chemical and physical properties and different pore diameter range, it is necessary to select experimental methods for the target material. This paper introduces a new method of measuring pore distribution, which is a Low Field Cryoporometry NMR method. Based on the principle of the nanometer-confined effect, this method can measure mesoporous distribution of different porous materials and shale. The logarithmic pore diameter distribution and the pore diameter distribution histogram indicate that the shale sample's pore volume is mainly comprised of pores with a diameter of 80–500 nm, which is consistent with the pore statistical results of the SEM analysis. The porous size distribution (PSD) was obtained by Croporometry NMR (NMRC) for shale samples, which was compared with that from the measurements by Brunauer-Emmett-Teller Method (BET).

This method enlarges the scope of the classical gas adsorption method, then can be used to study pore diameters from 10 nanometers to micron size. Furthermore, it provides an important reference to the study of the pore structure of shale oil and gas reservoirs.
Thixotropic Conformance Sealant for Horizontal or Highly Deviated Wellbores
Authors: Vasquez Julio , Eoff Larry , Lewis Chris
Published: October 2017

Excessive undesired fluid production, either water or gas, is a widespread problem withinthe oil and gas industry that can detrimentally affect the profitability of hydrocarbon-producing reservoirs, thus limiting their economic life. A wide variety of chemical technologies have been implemented throughoutthe years for controlling unwanted fluid production with some degree of success. However, when these types of treatments are applied to horizontal or highly deviated wells, placement control becomes a critical factor. Depending on fluid density differences and wellbore deviation, conventional conformance treatments can slump/rise along horizontal sections, compromising the placement accuracy and overall treatment success. This paper discusses the development and application of a thixotropic conformance sealant (TCS) system specifically designed to help control unwanted fluid production in horizontal or highly deviated wellbores. The stress-dependent (thixotropic) rheological properties of the TCS system provides rapid viscosity increase afterplacement, allowing the treatment to remain in place until in-situ crosslinking occurs at a predicted time, helping provide a competent and precise seal across the targeted area.

The TCS system is based on an organic-crosslinked polymer gel system combined with optimized rheological modifiers. It provides a predictable and controllable crosslinking time to obtain adequate placement. It can be placed into the wellbore by bullheading or using a coiled tubing (CT) unit. Once it is strategically placed into the zone to be shut off, in-situ gelation is activated by the reservoir temperature, plugging the permeability of the treated area, thereby limiting undesired fluid flow. The TCS system can be formulated to allow penetration into the formation matrix or to bridge off at the formation face for limited leakoff, to help provide a controlled and shallow penetration at the formation face. Laboratory data ispresentedas well as preliminary results of field applications.

Other thanthixotropic cement slurries, the TCS system is the first conformance technology tailored to horizontal applications within the oil and gas industry, helping reduce excessive undesired fluid production while extending the economic life of the wellbore and reservoir. The TCS system is applicable to different completion types such as openhole, slotted liners, openhole gravel-packs (OHGPs), and casedhole gravel-packs (CHGPs), among others.
Technical Integrity Management System
Authors: Hasanah Uswatun , Wibisono Sigit
Published: October 2017

In Total E&P Indonesie, Technical Integrity Management System (TIMS) is the means of ensuring that the people, system, processes and resources which deliver technical integrity are in place, in use and fit for purpose over the whole lifecycle of the assets, with purpose to avoid major accidents whilst meeting the production objectives. The system covers 4 key elements: plant, people, process and performance.

Total E&P Indonesie TIMS is applicable to all operational activities and assets under TEPI custodianship, from early conceptual studies, engineering, construction, and operations up to sites restitution. Adherence to this Integrity Management System is applicable for all TEPI personnel, contractors, sub-contractors, suppliers, service companies or any other organizations or personnel performing work in connection with TEPI activities and/or assets.

The paper will provide sharing experiences of Total E&P Indonesie in implementing Technical Integrity Management System with the feedback from the operational entities as the risk owners.

The objectives of Technical Integrity Management System are managed through following steps: –Set up integrity policy and procedures: issuance of company procedures.–Set up integrity management network: appointment of Discipline Integrity Engineers (DIC) and Specific Elements Lead Engineers.–Set up and monitor Integrity Performance: Sites, Entities and Affiliate Integrity Dashboard reporting and monitoring.–Major Integrity Threats (MIT) workflow: Identification of potential integrity threats, threat's risk evaluation, mitigation and remedial action definition, MIT declaration, MIT actions follow up, MIT closed out.–Manage Safety and Environmental Critical Element (SECE) based on Technological Risk Assessment (TRA) study result: SECE identification, alignment, implementation, reporting and follow up.–Management review and endorsement: management review through specific meeting.–Audit and verification: cross functional entities verification.

Main keys contributing to the success of the prevention of Major Risk in oil and gas operation is the active participation from all of the involved entities with excellent cooperation and coordination.

TIMS has been implemented for the last 5 years in Total E&P Indonesie. Improvement effort is continuously identified and implemented through the years.
Guidelines for the Environmental Monitoring of Oil and Gas Industry in Italy: Seismic, Ground Deformation and Reservoir Pressure Measurements
Authors: Macini P. , Mesini E. N. , Antoncecchi I. , Terlizzese F.
Published: October 2017

Today, HSE issues, environmental conservation and social acceptance are paramount in all industrial sectors. In particular, the social and environmental impact of E&P industry must be wisely evaluated and monitored. Following this direction, the Italian Oil & Gas Safety Authority (DGS-UNMIG, a Directorate General of the Ministry of Economic Development) issued a new set of monitoring guidelines for future licensing and E&P operations in Italy. After the seismic sequence of May 2012 in Northern Italy, a public discussion pointed out that these earthquakes could have been related to possible "anthropogenic" causes, i.e., a seismic activity induced or triggered by underground fluids withdrawal. For this reason, the Italian Department of Civil Protection appointed an independent international scientific commission to evaluate all available geoscience data to shed light on this hypotesis. In particular, three production fields, located near the epicenters of the seismic sequence, were closely examined: 1) a geothermal field; 2) an underground natural gas storage field; 3) a mature oilfield with reinjection. According to the conclusions of the above International Commission, the National Oil & Gas Safety Authority issued a new document of monitoring guidelines. In particular, future E&P operations in Italy must be complemented by properly designed monitoring networks aimed at controlling the: a) seismic activity; b) ground deformation; c) reservoir pressure. The monitoring networks must be implemented as soon as practicable when licensing is granted, in order to evaluate prior local seismicity and ground deformation with a sufficient accuracy. Moreover, monitored data must be made available to the safety Authorities, and thorough informative actions to residents and stakeholders must be properly carried out. The paper illustrates the above guidelines, the recent agreements signed with the Emilia-Romagna Regional Government and the present monitoring performed at selected Italian pilot test sites, according to the indications contained in the abovementioned guidelines.
Shallow Reservoir Development in Mature Field - From Hazard to Resources
Authors: Setiawan T.. , Putra A.. , Az-Zariat A.. , Rinjani K.. , Brahmantio R.. , Herawati S..
Published: October 2017

TUNU is a gas condensate field situated in the swamp environment at the edge of the Mahakam Delta, East Kalimantan – Indonesia. Hydrocarbons are accumulated in multi-layer reservoirs deposited within a deltaic environment. The field can be divided into two intervals which are Tunu Shallow Zone (TSZ) (between 600 and 2,200 mSS – typically unconsolidated and strong aquifer support) and Tunu Main Zone (TMZ) (between 2,200 and 5,000 mSS).

Since the field start up in 1990, it has delivered 9 Tcf of gas production. At the beginning, the field's first development was focusing on TMZproduction, where the gas reservoir at TSZ was only considered as hazard for drilling. Through time, TMZ is more and more depleted; hence development of TSZ is the new focus.

TSZ dedicated development started in 2007 by drilling two horizontal wells, each targeting individual channel followed by drilling of four deviated twin wells. Given the excellent result, new campaign of TSZ development was kicked off. Since then, more than 185 TSZ wells have been drilled contributing to 40% of around 700 MMScfd of total field production. This is resulted from improvement on selection of new wells target, cost effective well architecture and efficient reservoir management.

The first seismic survey targeting TSZ was performed in 2009 and since then TSZ development relied on detailed interpretation of seismic anomalies. Performing detailed interpretation is a major challenge on designing economical wells. This difficulty has been accentuated by recent downturn of gas price; hence having full field geobody inventory is becoming crucial. A geomodel was therefore built to have an exhaustive view of TSZ resources.

Optimization in selecting well architecture is also deemed necessary. Tubing-less completion with Chemical Sand consolidation (SCON) was assessed and shown that it can give more cost effective completion compare to gravel pack completion. Drilling cost could be reduced up to 30 % by using tubing-less completion with SCON.

Production optimization can be achieved by carefully implement the efficient reservoir management technique, e.g. maximize the number of completed reservoir zones without risk to safety and production, selection of best reservoir zone for first production, and implementation of flowline debottlenecking to accommodate hepta-mingle wells.
Essential Leadership Attributes for Engineering Managers in the Petroleum Industry
Authors: Lau Hon Chung
Published: October 2017

Based on a review of the leadership literature and personal observations, the author proposes a new leadership model for engineering managers (EM) in today's petroleum industry. This model consists of five essential leadership attributes. They are technical leadership, task leadership, relational leadership, change leadership and authentic leadership. Technical leadership refers to the ability of the EM to manage projects that are technically complex, multi-disciplinary and are subject to a high degree of technical uncertainty, such as field development planning. Task leadership refers to the EM's ability to be result- focused so as to complete the project on time, within budget and according to scope. Relational leadership refers to the EM's ability to motivate, challenge and support his or her team members to do their best. Change leadership refers to the EM's ability to promote innovative improvements to the organization and adaptation to external changes. Authentic leadership, which underpins all other leadership attributes, refers to the EM's ability to lead according to his or her core values which are ethical, commendable and consistent with those of his or her company, key stakeholders and the community. Suggestions on what universities, companiesand technical professionals can do to provide or acquire leadership training are also given.
Stress Corrosion Cracking on an Insulated Austenitic Stainless Steel Pressure Vessel
Authors: Hapsoro Padang Wikar
Published: October 2017

Stress corrosion cracking (SCC) is one failure mode that may occurred on hot insulated austenitic stainless steel pressure vessels and piping. In 2007, Badak LNG experienced this problem on its Amine Regenerator pressure vessel where the shell are insulated and made of Austenitic Stainless Steel Grade 304L. The paper will share the fact and findings, failure analysis, improvement to prevent recurrence, repair methods and inspection.

During the Train E overhaul in May 2007, cracks were observed on the shell exterior of Amine Regenerator pressure vessel. The cracks mostly occurred above the external vessel stiffening rings. Results of the failure analysis concluded that the pressure vessel failed by chloride induced stress corrosion cracking, due to moisture accumulation and the presence of chlorides at the affected locations in combination with a vessel operating temperature of 99 °C to 125 °C. Repairs were made by a combination of flush patching and weld built up methods.

In addition to a 100% non destructive examination (NDE), a pneumatic leak test was conducted to ensure the integrity of the pressure vessel. Some improvements were implemented to prevent problem recurrence, i.e. coating application on shell external wall surface, implement new specification of thermal insulation and modify the stiffener ring. Further thorough inspections to ensure that no more SCC exists on the pressure vessel were performed using precise NDE tools, i.e. AE (Acoustic Emission) and TOFD (Time of Flight Diffraction). The results were no more cracks indication found.

Currently, the pressure vessel has been in service for almost 10 years and no operational issues found related with SCC.
Application of Enhanced Gel Strength Concept for PPD Chemical Optimization in Banyu Urip Export Pipeline
Authors: Dwitawidi Alinda
Published: October 2017

Banyu Urip crude contains 26% wax which can provide flow assurance (FA) challenges in a stabilized crude pipeline exposed to lower temperatures. Injection of Pour Point Depressant (PPD) chemicals has widely been considered as an effective method to ensure flow assurance for moderate waxy crude. For the Banyu Urip field in Indonesia, PPD injection was compared to other methods and found to be the best option from a cost and operability perspective. Nevertheless, it still contributes to almost 20% of Banyu Urip operating costs. Optimization of this chemical usage brings benefit both for the Operator and also for the government through lowering operating costs.

In the past, the flow assurance of waxy crude was determined by measuring \Pour Point (PP) temperature. At temperatures below this PP, the crude will stop flowing. PP measurement has several limitations, including providing a lower representation of the actual conditions. In this paper, a restart pressure simulation model and pilot experiments were used to provide a more realistic condition assessment and helped to avoid over-injection of PPD.

In the enhanced gel strength concept, a weak waxy crude gel may be formed in the pipeline below its PP and still be breakable by applying pressure within the pipeline's Maximum Allowable Working Pressure (MAWP). Furthermore, the size of pipeline and the wax's natural insulation capability provides a radial temperature profile which can prevent the core pipeline from seeing a rapid temperature reduction. A pilot experiment for establishing a radial temperature profile has been conducted in by the Operator leveraging local university support. The same approach will be conducted for an upcoming flow loop experiment for restart pressure validation.

In Banyu Urip, the initial PP target was set at 24°C based on the lowest seabed temperature observed in the offshore section of the pipeline. This target resulted in a PPD injection dosage of ~500 ppm. Using the enhanced gel strength concept, the required PPD injection rate was reduced to ~300 ppm. Further reduction is expected after conclusion of the radial temperature profile and flow loop experiments.
Temperature Dependent Influence of Nanoparticles on Rheological Properties of VES Fracturing Fluid
Authors: Sangaru Shiv Shankar , Yadav Prahlad , Huang Tianping , Agrawal Gaurav , Chang Frank F.
Published: October 2017

The use of nanoparticles has been demonstrated to enhance the rheological properties of the viscoelastic surfactant (VES) fluid. However, their influence on the rheological properties as a function of temperature is not well known. In this study, a detailed analysis of improved rheological properties and thermal stability of the VES fluid beyond their optimal working temperature was conducted. The effect of nanoparticles was also studied.

A base VES fluid was prepared with the required amount of surfactant along with an ionic strength agent dissolved in sea water. The desired type of nanoparticles in required amounts were added to the base VES fluid and homogeneously dispersed. Different types of nanoparticles were added to prepare corresponding nano-VES fluid. Rheological properties of the base VES fluid and different nano-VES fluids were measured against variable shear rate. The fluids were tested at a temperature at which the base fluid shows highest gelling behavior, and at temperatures above and below that value.

Results, Observations, Conclusions: The initial thermo-viscosifying effect and eventual thermo-thinning effect with temperature havebeen widely observed for viscoelastic surfactants based fluids. The effectshavebeen attributed to the effect of temperature on the structural changes of wormlike micelles. Nanoparticles being of the dimensions that are comparable with the thickness of these wormlike micelles are readily able to incorporate themselves into these structures and influence their rheological behavior. These interactions change both with respect to temperature and shear rate applied on them. Further, these interactions differ depending on whether the fluid is in the thermo-viscosifying region or the thermo-thinning region with respect to the temperature. Based on the kind of nanoparticle used, significant improvements in rheological behavior from a fracturing fluid perspective have been observed. In addition, shear rates at which a shift from Newtonian to non-Newtonian behavior with respect to shear rate occurs, has also been observed to change.

A greater insight into the effect of nanoparticle additives on temperature related rheology of VES fluids has been provided. This understanding is crucial for the optimization of a VES fracturing fluid based on the well-to-well changes in temperatures.
The Characteristics of Hydraulic Fracture Growth in Woodford Shale, the Anadarko Basin, Oklahoma
Authors: Hai Qu , Ying Liu , Chuande Zhou , Liancheng Ren , Qinwen Wei , Yancang Lv , Jun Hou
Published: October 2017

The Woodford shale in Oklahoma is an ultra-low permeability reservoir that must be effectively fracture stimulated for the development of shale oil. Hundreds of horizontal wells with 4000ft-5000ft lateral length were stimulated by hydraulic fracture technology. Several pilots with 9000ft lateral length were also tested to figure out the relationship between lateral length and outcome. The research found that the shape of manual fracturein Woodford(WDFD) formation is the most important factor affecting the production.

The wells were stimulated in stages with large hydraulic fracture treatments. However, production isn't directly related to the size of the stimulated volume. Microseismic mapping techniques, simulation method, post-production analysis and formationstress calculation are cooperated to study the characteristics of fracture extension. It is found that there are two kinds of fracture shape which are different from Barnett shale. This paper will test the effect of fracturing liquid and proppant on the fracture growth; The values of triaxial stresswere obtained in the neighboring layers and WDFD formation; Finally, the pilot wellisan example to illuminate fracture extension.

Understanding fracture growth in the Woodford shale will enhance the development of the play by helping operators optimize fracture completion and well placement strategies.
Augmenting Deepwater Well Control with Managed Pressure Drilling Equipment
Authors: Johnson Austin , Piccolo Brian , Pinkstone Henry , Anderson Bo , Fraczek Justin
Published: October 2017

The objective of this paper is to describe howApplied Surface Back Pressure -Managed Pressure Drilling (ASBP-MPD) can be used to augment the limitations of conventionaldeepwater well control. This paper will discuss equipment design and operating philosophy as well as expand on what actions can be taken to respond to an influx while remaining within the primary well barrier.

A critical evaluation of deepwater well control has been performed uncovering several limitations which can be mitigated with anASBP-MPD system. As such, this paper will describe the disadvantages of shutting in the Subsea Blowout Preventer(SSBOP) such as the risk ofnon-productive time associated with stuck-pipe and the total influx volume increase associated with the process. Additional items discussed in this paper include managing an influx in the riser and inaccurate conventional kick detection methods.

The paper will explain howdeepwater well control can be augmented with anASBP-MPD system by sealing the wellbore with either an MPD annular preventer or an MPD riser seal. Closing the MPD annularforms a wellbore seal on drill pipebefore the mud pumps are shutdown enabling a closed system flow check and the ability to add back pressure with the MPD choke to reduce influx volume. The activation of an MPD riser sealing system provides an even faster influx response time, as drilling operations are executedin a closed system with a continuous wellbore sealwhile diverting flow through an MPD choke. Additionally, since the riser is already sealed, an MPD sealing system serves as reliable protection from a sudden riser gas unloading event which can occur in seconds. By redefining the primary well barrier in the above context, ASBP-MPD equipment can be used to circulate a small influx out of the wellbore without closing the SSBOP while remaining within the limits of the primary well barrier. Finally, accurate flowmetering of flow out and flow in provides a level of advanced down hole event detection that reduces influx volumes and further eliminates the need for a conventional flow check prior to confirming that an influx event has occurred.
Improve the Stability of Sand Feeding Process for Liquid CO2 Fracturing with Synergetic Multi Disciplinary Systems
Authors: Meng Siwei , Liu He , Yang Qinghai , Xu Jianguo , Duan Yongwei , Chen Shi
Published: October 2017

Liquid CO2 fracturing is a novel stimulation technology, which helps realize multiple objectives such as conservation of water, sequestration of greenhouse gases and enhancement of single-well productivity and ultimate recovery. The blender used in PetroChina Jilin Oilfield is a huge vertical pressure vessel with a short auger conveyer at its bottom, which has poor sand controllability on sand feeding process. Making matters worse, the viscosity of liquid CO2 is very low, resulting poor sand-carrying capacity, which further enhances the difficulty on sand feeding.

Stability of sand feeding process is improved via coordination of multi-disciplinary systems. 1) Develop new additive system for liquid CO2, which can enhance the viscosity efficiently and has little damage to reservoir; 2)Adjust the auger conveyer structure to increase its control ability; 3)Ensure the pressure difference between in-tank and outlet of blender less than 0.05 MPa, by adjusting phase behavior of CO2 during treatment, liquid supplement rate to blender and opening degree of butterfly valve; 4) Apply casing fracturing instead of tubing fracturing, to enhance the pump rate.

Results are as follows. 1) Two new additive systems are developed, both can enhance the viscosity to 5cp with a dosage of 1wt%. 2) Tilted auger conveyer is applied, thus increases its controllability on sand feeding and accuracy on sand ratio measurement. 3) Small positive differential pressure between in-tank and outlet of blender forms easily in winter, but difficultly in summer. The reason is that the temperature is high and large amount of CO2 is gasified, resulting in the increase of in-tank pressure. In this case a heat exchanger is needed to sub-cooling CO2. 4) By apply casing fracturing technique, the pump rate can rise from 3m3/min to 8m3/min, make the sand feeding process much easier.

The sand feeding process of liquid CO2 fracturing is optimized via coordination of multi-disciplinary systems, which increases the sand ratio and total sand volume during fracturing, improves the construction stability, and eventually enhances the stimulation effect.
New Generation Inflow Control Device to Maximize Well Productivity during Every Phase of a Well's Life
Authors: Sharma Hemant K , Al-Mulhim Abdulrahman K. , Al-Mutairi Saad M. , Al-Shammari Nayef S.
Published: October 2017

Oil production from long horizontal wells can pose a challenge, due to reservoir heterogeneities and the presence of fractures. In such cases, the result is an imbalanced production profile leading to early water breakthrough. Once water coning occurs, oil production may be severely decreased, due to the resistance to oil flow from the water contributing zone. To reduce this imbalance, inflow control devices (ICDs) are placed in compartments across the entire lateral length of the horizontal, which compensates for permeability variation. The compartments are separated from each other using openhole packers and constrictors. The passive ICD's are always opened to production. In cases where specific ICDs starts to contribute undesired water production, water shut-off of the length below this ICDis performed; eliminating all flow contribution, below the ICD.

A new generation of Active/Adaptive ICD's has lately been installed in some openhole horizontal producers. The Active/Adaptive ICD's can be selectively closed/opened by a setting tool to control the water production. Using this completion, the oil production has been substantially increased (some wells more than 200 %) and consequent decrease in the water production to at least 50 % and even dry.

To operate the new generation of ICDs, a new generation modular anchor and Universal Shifting Tool (UST)is used. Thisis the first downhole application of this tool worldwide for selective shifting of ICDs in a horizontal wellbore. The tool uses hydraulic pressure created by an electric motor to generate force. It provides setting assurance by real time monitoring with controlled setting force, distance and speed. With the signature from the log, the position of the ICD sleeve can be confirmed — whether opened or closed and there is no need to have additional production logging runs to confirm the position of the sleeve.

This paper details the design and advantages of the new generation of active/adaptive ICDs in horizontal wells and how the new "modular anchor and UST" is being effectively used for selective operation of the ICDs.
A New Approach for Downhole Tools Deployment Training
Authors: Gonzalez Roberto E. , Chapman Lawrence D. , Geer Ronny K.
Published: October 2017

Advanced employee education represents the backbone of current competence management programs across the oil and gas industry while the demand for more efficient training programs is increasing over time. The employee education task becomes more difficult when the incorporation of hands-on training is essential. This document is to share the experiences gained by an oilfield service company in the successful development and deployment of different scenarios and delivery methods that let students practice downhole tools installations in a controlled environment using a fully operational rig.

Previous approaches to downhole tools training used slideshow presentations, tools schematics and tear-down simulations to explain the proper function of a tool. These techniques helped students understand how the tool mechanisms interacted and how the tool functioned. However, they were not very successful in helping students fully comprehend the operating procedure and associated key indicators in a rig environment. Special training assemblies were designed to simulate various downhole conditions and enable the students to execute the operation on a real rig.

Implementing these simulated scenarios in multiple product line training sessions helped the students move closer to full competence on individual qualifications. Depending on the specific task, students were required to complete additional "on-the-job" (OJT) tasks in the field under supervision of a qualified employee. Students also gained a full understanding of the tool behavior, allowing them to work with minimal supervision in real-life situations. Applying this methodology in the areas of completion and wellbore intervention operations has been particularly successful. Pipe manipulation and pressure application during the device activation is imperative, and is one of the most difficult tasks to explain without using simulated scenarios. Observed results in personnel with no previous experience in the areas of specific training have been also positive. The incorporation of a real rig and deployment of downhole devices helped these individuals understand the operation and processes associated with a rig-specific deployment or tool installation. This additional training has helped them to develop their work in other areas or product segments within the organization such as quality and reliability, finance, human resources, HSE, etc.

The service company consolidation of global product segment training into two primary locations enabled the interaction, optimization and standardization of existing programs and facilitated cross-product line knowledge sharing of common practices that used to be learned separately. The explanations of training scenarios shown in this document would help in the creation and development of training programs across the oil and gas industry.
HPHT Test Packer for Use in WBCU Applications; Reduce Trips, Increase Performance, Protect the Wellbore
Authors: Oberg Levi , Holloway Lan , Harrington Kevin
Published: October 2017

A liner-top test packer is a device that is used to verify the integrity of a liner top and cement job in the annulus of a liner. This operation can detect a liner top leak that could result in hydrocarbons migrating into a wellbore. One method to save a trip is to run a liner-top test packer in combination with casing cleanup tools in a combined test and wellbore cleanup run. This enables an operator to verify liner integrity, remove scale, debris, and metal shavings from a wellbore, polish a liner top, and displace fluids all in one trip.

As well integrity assessment becomes increasingly important, liner-top test packers must perform with reliability at higher temperatures and pressures, often in deviated wells, under high flow rate situations, and in aggressive muds and completion fluids. These high pressures require a tool that removes hydraulic loads from the liner top, while testing with up to 11,000 psi differential pressure.

Historically, liner integrity testing has been performed as an independent operation prior to running wellbore cleanup tools and displacing the well. Today, test packer tools are designed so these two independent operations may be combined into a single trip. Though value is added through reduction in operating time and risk, liner-top test packers must perform reliably while minimizing debris that could compromise subsequent completion operations.

This presentation will discuss typical high-pressure/high-temperature (HPHT) test packer applications and case studies for wellbore cleanup jobs. HPHT objectives were met by reliably sealing 11,000 psi pressure at 400° F and eliminating harmful loading on the liner top.
Improvement and Prospect of Ultrashort Radius Lateral Drilling Technique
Authors: Ming Eryang , Li Yiliang , Li Tao , Huang Shouzhi
Published: October 2017

The ultrashort radius lateral drilling technique has applied more than 20 wells in China, and it was reported that this technique increased the production of mature oil wells by 3 to 5 times in average. However, when the casing grade was relatively high, the flexible drilling tool was cut off by the sharp edge of open window. This paper will introduce a method to improve this technique.

By studying the failure case, there were two obvious defects for this drilling tool. First, the shell material was too soft. It was radially stripped of 2 to 3 mm. Second, the design of transmission fork was unreasonable. The cylindrical pins of transmission fork were placed from the outside of shell and were covered by welded discs. When the shell was stripped, pin was easy to drop off and causes disconnection. To find the essential cause, we deduce kinematics and dynamics analyzes, and redesign the structure of transmission fork. Test shows the performance of new tool is much better.

This paper introduces kinematics and dynamic to redesign the ultrashort radius lateral drilling tool, which improves the performance by principle. Though kinematics analyze, we found the rotational speed inhomogeneity might cause inefficient drilling depth, even sticking of tool in some extreme cases. Tough dynamic analyze, we found the additional torque caused by rotational speed inhomogeneity might cause the vibration of drilling tool, which may cause more serious problem. To solve these problems, the universal joint was design into constant velocity universal joint and the mounting position of transmission part was placed from inside to give enough margin for shell stripping off. After these work, the ultrashort radius lateral drilling tool has less vibration and provides continuous and stable torque. This method improves the efficiency and success rate of this technique.

This paper updates the design method of ultrashort radius lateral drilling technique, makes it much reliable and efficient. It will give the promise for the next generation technique, the ultrashort radius lateral coring technique.
Proposed Modification of Abandonment and Site Restoration Mechanism in Gross Split PSC for Marginal Field in Indonesia
Authors: Kurniawan Temmy Surya , Jaenudin Jemi
Published: October 2017

Referring to the Ministry of Energy and Mineral Resources regulation in 2017 number 8, the government intends to encourage contractor in Indonesia to conduct exploration and exploitation activity to be more effective and efficient in way of implementing gross split PSC in Indonesia, especially for expiry block. In 2018-2028, there will be 23 expired blocks. Some of those blocks have been reaching the marginal category and they are needed to be evaluated with current regulation of fiscal regime. In marginal block, abandonment and site restoration (ASR) cost is being issue for economic feasibility.

To evaluate impact of ASR mechanism in Indonesia's gross split PSC for marginal block, a model block is evaluated. The model has high cost per barrel (USD39/boe) and ASR cost is 34% of total cost. Economic evaluation for this marginal block with ASR issue is assessed using NPV as feasibility indicator. The evaluation result using Indonesia's gross split PSC is not favorable for contractor. This paper presents modification of ASR funding mechanism in Indonesia's gross split PSC.

Modification of funding mechanism consists of scenario with ASR cost is fully taken from government take, ASR cost is taken from government take when the cash flow of contractor is negative, and ASR cost is shared between government and contractor based on total split This modification gives positive result for contractor side.
The Study of a Novel Modified Silica Nanofluid for Pressure-Decreasing Application in the Ultra-Low Permeable Formation
Authors: Zhao Mingwei , Gao Mingwei , Dai Caili , Li Yuyang , Lv Wenjiao
Published: October 2017

In most low-permeability reservoirs producing regions of the world currently, for pressure continuous increase in the water-injection process is becoming increasing important issues when water flooding is conducted. In this work, a novel hydrophobic silica nanofluid (SNF) through modified by triethoxy(vinyl)silane (TVS) is adopted to adsorb on the surface of core so as to acquire hydrophobicity and decrease the water-injection pressure. Fourier transform infrared (FTIR) spectroscopy shows that methyl headgroups are successfully grafted on the surface of silica nanoparticles (SNP). The decrease of SHN (SHN) certifies the success of modification. Dynamic light scattering (DLS) result reflects that the modified SNF has excellent hydrophobicity and superior dispersibility. The wettability transformation of core surface from hydrophilic to lyophobic is determined by the water contact angles. The results of laboratory displacement tests show that the SNF has the remarkable pressure-decreasing ability due to adsorption on the surface of core.
Active Tag Control Sliding Sleeve Fracturing Technology
Authors: Lichen Zheng , Jiaqing Yu , Yucai Wang , yang Gao , Xiaohan Pei , He Liu
Published: October 2017

The rapid progress in fracturing technology pushes the oilfield development to bigger scale, The traditional Multi-stage fracturing technology such as ball fracturing, quick drillable bridge plug fracturing have problems like limited fracturing stages, high operation risk and high later operation cost etc. Multistage fracturing technology based on Radio Frequency Identification (RFID) was developed, it overcomes the shortcomings of traditional fracture tools, but the low tag recognition rate, speed limitation and complicated structure limit its further application. A new generation active tag control Sliding sleeve Fracture tool is developed. This fracture tool is composed of vacuum energy storage system, electric control direction valve, sliding sleeve, microcomputer control system, battery group, RFID antenna and active tag. The vacuum energy storage system provide power for the open and close of the sliding sleeve, the operating pressure is the union of the surface fracture pressure and the head of the liquid, which can be controlled on the ground. Electric control direction valve controls the oil flow direction and control the opening and closing of the sliding sleeve. The antenna works only in low power mode and picks the signal from the active tag. The active tag ball contains micro battery inside and signal producing system, it will be wake up by a special instrument before lower into the well, the battery will sustain the tag work for at least 30 minutes. The active tag signal can be picked up by the antenna at 100% success ratio and without speed limitation. During the fracturing process, the active tag will be dropped in the well to control the opening and closing of the sliding sleeve in any specific fractured interval. After fracturing, pressure wave is applied to open all the sliding sleeves and the production operation begins. Compared to the first generation RFID control sliding sleeve, the Active tag control sliding sleeve has relative simpler structure, more compact dimension, longer battery service life, more reliability and control flexibility, which is more suitable for the oil field fracture application. The active tag signal transfer mechanism improve signal transfer reliability greatly and without speed limitation, which lowers the power consumption of the antenna and will provide long battery service life, the vacuum energy storage system simplify the structure greatly and the sleeve active pressure can be controlled on the ground.