bluuebunny/crossref_metadata_2025_split huggingface dataset:
Physical Concept Validation Testing Performed for a Pore and Fracture Pressure Margin Prediction System during Offshore MPD Operations
Authors: Johnson A. , Piccolo B. , Leuchtenberg C. 
Published: August 2016

Abstract
A pressure determination system (PDS) was field tested to progress Managed Pressure Drilling (MPD) from a reactive system to one that prevents well control events from initiating. Physical testing performed on an offshore drilling operation successfully demonstrated the capability of the PDS to detect a simulated, unsafe change in fracture margin without incurring significant losses in August 2014. A summarized overview of the test method, conclusions, and results will be discussed as well.
The PDS Pressure Control Valve (PCV) is designed to oscillate its position size in a repeatable and gradual fashion and analyze the behavior of Applied Surface Back Pressure (ASBP), Bottom Hole Pressure (BHP), and Flow Out indicators over time. In the event that average BHP begins to near a drilling margin, the behavior of the above indicators at the crest or trough of a wave cycle will momentarily deform indicating an unsafe change in a drilling margin trend that will eventually lead to a recordable well control event if wellbore pressure is not proactively adjusted. Since, average BHP has continuously remained within drilling margins during this process, any resultant gain or loss is negligible. Once the threat of a well control event is detected, the MPD PCV will adjust wellbore pressure to a safer value to prevent the occurrence of a well control event.
During field testing, the PDS concept was verified with two assessments, signal transmission reliability and simulated fracture detection. Both tests were performed in open hole of a medium depth well with a rotating and reciprocating drill string and the mud pumps running. The signal transmission reliability test validated that the PDS can oscillate PCV position in a controlled and consistent fashion as well as create highly repeatable behaviors in ASBP, BHP, and flow rate waves over time. The simulated fracture margin test demonstrated that the PDS has the sensitivity to detect a fracture margin at 20 psi above the driller's intended wellbore pressure with a negligible volume of losses while the PDS PCV oscillated wellbore pressure as described above.
Prior to field testing, a SIT (System Integrity Test) was performed on the PDS equipment installed on MPO's MPD Pressure Control Manifold (PCM) to ensure the system was prepared for concept testing. The SIT was performed with the MPD PCM isolated from well bore riser returns in August 2014. The field tests performed offshore, were previously performed as an initial test, at the MPO Dubai Training Center Flow Loop where the PDS concept was also successfully validated in a laboratory environment. During those tests, the sensitivity of the PDS system was also demonstrated by validating that a 4 inch Coriolis meter in a small, closed loop system was able to detect less than a 1 gallon difference in flow.
Study on Structure Parameters of Reverse Circulation Drill Bit Secondary Injector Device Based on Injector Coefficient
Authors: Yong Huang , Lihong Zhu , Deyong Zou , Hualin Liao , Jinying Wang , Jinshen Yan , Yugang Zhou , Zhibin Wang 
Published: August 2016

Abstract
The hollow-through DTH hammer reverse circulation continuous coring drilling technology has been successfully applied to well drilling. During its application, reverse circulation drilling sometimes does not work in broken formation or under leakage formation condition. Difficulty in sampling is another problem. These problems are primarily caused by the injected gas. It comes into the fissures and not drives the reverse circulation, thereby failing to generate an adequate pressure at the hole bottom to deliver the cuttings into the central channel.
The reverse circulation bit is the pivotal factor in the formation of reverse circulation. To improve the reverse circulation effect, this paper proposes that a secondary injector device be set at the central hole of the original reverse circulation bit. The injector device used for the hollow-through DTH reverse circulation bit is a gas injector designed with the gas injecting principle. Based on the structure principle of the injector and the actual structure of the DTH reverse circulation bit, it is used the bottom nozzle of the bit as injector nozzle and add a pressure diffusion slot, so a multi-nozzle injector structure at the bottom of the bit is formed.
The secondary injector device can effectively improve the reverse circulation effect of the hollow-through down the hole (DTH) hammer drilling technology. The influence of the four structural parameters, namely, secondary injector hole diameter d, center hole diameter D, injector hole angle θ, and distance h from the injector hole to the reverse circulation drill bit bottom, on the injector coefficient n was studied by computational fluid dynamics (CFD) simulation to determine the structure size. The CFD results were verified by experimental method. The results showed that the reverse circulation effect changed with the changes in the secondary injector device structure parameters d, D, θ, and h. A combination of structure parameters allowed the drill bit to achieve the best reverse circulation effect. Considering the effects of the four parameters, d=11 mm, D=44 mm, θ=30°, and h=180 mm were the more rational parameters. Moreover, laboratory experiments were conducted to verify the CFD simulation results. The simulation results that showed the variation of n with different structure parameters were compared with the experimental test results. The comparison showed an error of less than 15% between both results, further verifying the rationality of the structure parameters.
The hollow-through DTH hammer-based reverse circulation continuous coring drilling technology is featured by reverse circulation of fluid medium through the entire hole and continuous upward conveyance of the cores during drilling. This paper studies the structural parameters of the secondary injector device of the reverse circulation drilling bit in order to improve the rate of core recovery.
A Brief Introduction to High Temperature and Foam Free Water Based Drilling Fluids
Authors: Mojammadi Mojtaba Kalhor , Taraghikhah Shervin , Nowtaraki Koroush Tahmasbi 
Published: August 2016

Abstract
Water-based drilling fluids are the most commonly used of the mud systems. High Temperature and Foam Free Water Based Drilling Fluids has been designed for controlling the rheological and filtration and foam properties of water based drilling mud under down-hole conditions.
This unique drilling fluids system has been developed to improve water based drilling operation's speed and save the drilling cost while reducing their environmental impact for rheology and filtration control at high temperatures. Specially-formulated fluid has good lubricity and low toxicity, and at the same time do not create significant foam and corrosion in during drilling operation. This drilling fluids system's unique chemical structure enables this system to provide multifunctional properties such as surface tension reduction, foam control, and viscosity stabilization, HPHT fluid loss controller.
This new drilling fluids system is formulated by using special HPHT synthetic polymers and specialty additives to reduce HPHT fluid loss of the system and provide maximum shale inhibition in HPHT wells, limitation of foam, and increasing ROP. This system significantly reduced the degradation of polymers and fluid loss additives in WBMs up to 375 °F and increase the rheological and filtration stability to improve the thermal stability in higher temperature environments. Experimental results from the performance of this product have been acceptable in down-hole conditions. This also reduces cost and logistics issue especially in offshore and extend the thermal temperature limitations of standard system components, premium starch derivatives and XC polymers.
In present work, laboratory evaluation of specially-formulated fluids to enhance the properties of the HPHT water based drilling mud was investigated. We put and maintain specialty chemicals in from the beginning operation and we did not experience foaming, ever!
Effects of Injection Pressure on Wellbore Stress Using Flow-Stress Coupling Method
Authors: Bataee Mahmood , Irawan Sonny , Ridha Syahrir , Hematpour Hamed , Hamdi Zakaria 
Published: August 2016

Abstract
Enhanced Oil Recovery (EOR) injection methods are increasingly applied globally as the effective method in oil wells. Fluid injection alters the formation stress around the wellbore. In this study an iterative coupling method is proposed to evaluate wellbore stresses for one cycle of water alternating gas (WAG) injection. The effective parameters such as pressures, temperature, saturations and stresses are obtained for the multiphase flow condition using mathematical modeling. In this study, finite difference method is used to calculate pressure, temperature and saturations; and finite volume method is applied to evaluate stresses. Iterative coupling method is used to improve the accuracy of the results. The results show the pressure is boosted around wellbore after injection and how the water bank is pushed by injected gas. Maximum value of radial stress is obtained in the direction of horizontal maximum in-situ stress. Maximum value of tangential stress is determined in the direction of horizontal minimum in-situ stress. Vertical stress around the wellbore is not related to horizontal maximum and minimum in-situ stresses. The shear stress values are small in comparison with other stress types. The accuracy of model results are increased by iterative coupling, which the maximum correction is about 20 psi (0.14 MPa) for pressure. The developed model is capable to be applied in the wellbore to ensure stability for different injection or production cases.
A Case Study: Field Application of Ultra-High Temperature Fluid in Deep Well
Authors: Liwei Wang , Bo Cai , Xiaohui Qiu , Yongjun Lu , Wen Zhai 
Published: August 2016

Abstract
In this paper, we will introduce the performances, research's process and a case study of ultra-high temperature fracturing fluid. The ultra-high temperature well is a carbonate formation with 205°C, located in HuaBei Oilfield, East China. The temperature of NiuDong carbonate formation is more than 200°C in HuaBei Oilfield in East China, acid-fracturing is an important stimulation for NiuDong reservoir. As known, the guar fracturing fluid is usually used less than 177°C because of guar molecule's performances, so we develop a ultra-high temperature polymer as pad fluid of acid-fracturing to stimulate the NiuDong carbonate, the polymer is a novel structural terpolymers which can be cross-linked by crosslinking agent and broken by APS. The structure of thickener is a key factor to increase the high temperature resistance of polymer, so a novel molecular structural polymer with C-C bond backbones and C=C bond monomers is developed for the ultra-high temperature fluid, and the hydration group with C-C, C-S, C-N is also added in the side chains with the purpose of decreasing the dissolution time of the polymer. An organic zirconium crosslinking agent with amide groups is selected to crosslink the polymer fluid, and the cross-linking time is controlled. After cross-linked, the network structures of gel fluid like the uniformed petals in the scanning electron microscope, so the viscosity is very high. Under the conditions of 200°C, 170s−1 and shearing120 minutes, the residual viscosity is more than 130mPa.s, The evaluated tests show that carrying proppant of polymer fluid are good, low interfacial tension and low residues. The ultra-high temperature polymer fracturing fluid has been successful used in a Well of NiuDong sag. Ultra-high temperature polymer fracturing fluid provides a selection for the formation with more than 200°C.
Successful 20 Well Stimulation Campaign in a Mature Oil Field in Myanmar
Authors: Shaoul J. R. , Tkachuk I. , Chia D. J. , Nyo T. 
Published: August 2016

Abstract
Hydraulic fracturing technology is widely used to facilitate and enhance the recovery process from oil and gas reservoirs. Much worldwide experience has been gained in stimulating conventional and shale oil reservoirs; however achieving good stimulation results in mature (depleted) oilfields with moderate permeability can be challenging and can easily fall below expectations for a variety of reasons.
To narrow the gap between expected results and actual well performance after a successful fracturing treatment it is very important to understand the reservoir characteristics and the actual reservoir potential. Despite the common opinion that stimulating mature, depleted wells is unprofitable, experience shows that stimulating such wells can still result in substantial and profitable production increases.
Twenty hydraulic fracturing treatments performed on wells in a mature onshore oil field wells in Myanmar, in south-east Asia have shown significant increases in initial incremental oil production rate—on average by a factor of two, which was still below the expectations. The treatments have effectively increased cumulative production and arrested exponential decline by +62% per annum. The result is a flatter production profile and has higher sustained oil production rates.
This paper discusses the challenges seen and the results obtained utilizing hydraulic fracture stimulation in a mature oilfield. This case shows the importance of a proper candidate selection method, which has contributed to successful stimulation and improved oil recovery in this case.
Extending Life of Mature Oil Wells with Various Type of Siphon String Application in Offshore North West Java
Authors: Wibowo K. , Widyantoro B. , Kurniawan R. C. , Azizan Y. 
Published: August 2016

Abstract
Offshore North West Java (ONWJ) field has been producing since 1971 with multi-stacked layers, solution gas to weak water drive mechanism, most of wells are completed with dual strings and gas-lifted. This condition compromise a relatively shallow top packer placement. In some cases, abandonment pressure has been reached as characterized by low static liquid level below deepest gas-lift mandrel. Apart from that, tubing integrity is becoming important issue as fields are maturing.
Less operational complexity for the installation of siphon string or velocity string to tackle the two challenges above and better economic returns make it a better option compared to recompletion.
The applied strings are from 1.75″ QT-900 coiled tubing, installed with various configurations of packer, gas-lift mandrel, and length depending upon wellbore completion, artificial-lift concern and well integrity requirement.
Siphon string has been installed in 6 strings; whereby 3 strings with tubing integrity issue (well A, B and C), 3 strings with liquid level below deepest gas-lift injection mandrel (W, Y and Z). After installation, well A and B were flowing for 2 years before they were finally shut-in due to leak below the siphon string assembly. Well C had flowed for another 6 years before it was shut-in. Well X has been flowing since the inception of siphon string in 2006 until this paper is written, well Y has flowed for 8 years and well Z has been flowing for 1 year. An increase of 0.5% – 2% of recovery factors for these wells has created opportunity for other similar wells to continue or increase production.
The first part of the paper will describe on the candidate selection and well configuration, the second part of the part will cover the installation procedures, challenges and lessons learnt. Finally, production results comparison from pre and post installation is presented.
Integrated Holistic Approach to Drill Middle-East Region Sensitive Shales Successfully: Example of Ahmadi, Wara and Middle Burgan Shales in Kuwait
Authors: Khan Ali Nasar , Marie Safaa Mohamad , Gawwad Tarek Abdel , Subbiah Surej Kumar , Tan Chee Phuat , Povstyanova Magdalena 
Published: August 2016

Abstract
Kuwait Oil Company (KOC) was planning further development of the Sabriyah (SA) and Raudhatain (RA) fields by drilling a number of horizontal wells. Both fields presented considerable challenges that included, among other factors, drilling through several problematic shales. The major drilling issues experienced in the shales comprised of tight spots, packs-off, etc. To optimize the drilling process and minimize the risks while penetrating the shales, a decision to conduct a geomechanical study was made. The geomechanical study was focused not only on improvement of the mud weight program (mechanical wellbore stability analysis was conducted) but also on drilling fluid optimization as well.
The drilling fluid optimization analysis was carried out in order to evaluate the potential time-dependent wellbore instability mechanism(s) in the Ahmadi, Wara and Middle Burgan shale formations in the two fields, to define salt concentration for nominated mud types, and to develop solution and strategy to mitigate and/or manage the wellbore instability problems.
Based on the time-dependent shale stability analysis, recommendations were made for drilling the Ahmadi, Wara and Middle Burgan shale formations for water-based mud (WBM) and oil-based mud (OBM). Mud salinities were provided for several combinations of designed mud weight and evaluated breakout mud weight.
The following conclusions were drawn based on the geomechanical study: Water activity of the Ahmadi, Wara and Middle Burgan shale formations was moderately high. Hence, it was feasible to select an optimum drilling fluid design (whereby the mud pressure penetration was fully counteracted by the chemical potential mechanism) for WBM and OBM for the shale formations, even though overbalance pressure in the formations was relatively high. The Ahmadi, Wara and Middle Burgan shale formations could have been drilled using the designed mud weight programme and salinities for the two mud types without significant time-dependent wellbore instability problems in the analyzed planned wells.If the recommendations on mud weight and/or salinities were not fully followed, the shale formations could deteriorate with time due to either mud pressure penetration mechanism being not fully counteracted by chemical potential mechanism or over-dehydration. Increase in drag that could indicate formation deterioration should be established based on drilling parameters and rig capabilities.
Managing BHA Components Integrity with a Fatigue Management Workflow
Authors: Suryadi Hendrik , Li Ke , Brovko Katerina , Parkin Edward , Ossia Sepand 
Published: August 2016

Abstract
BHA integrity is important to successful drilling operations. Fatigue failure is the primary cause of twistoffs. There has been no method to predict and monitor fatigue life of BHA components while drilling. Current preventative methods include predefining the collar life based on past experience and tracking the cumulative pumping hours. When total hours reach the predefined life, the collar is junked. This method is inaccurate because the pumping hours do not accurately reflect the fatigue life of a collar. Regular inspections by nondestructive testing (NDT) to detect any cracks should reveral the initiation of fatigue failure. However, a collar can still consume its fatigue life, initiate a crack, and finally twist off while drilling, causing significant loss of time and money.
Fatigue damage consists of two stages, crack initiation and crack propagation, with crack initiation accounting for most of the total life. Rotating bending is the driving force for fatigue cracking. It induces cyclic stresses and strains at the stress risers, which are the fatigue-critical features. Fatigue data can be presented in the form of M-N curves, where M is the applied bending moment and N is the total life in number of cycles. The BHA bending moment distribution can be computed with a BHA analysis. Given a bending moment, the cyclic stresses and strains at the most critical feature of the most critical BHA component are typically determined with finite element analysis. The life of the most critical feature can then be calculated with the stress-life or strain-life curve of the collar material. This governs the life of the entire BHA.
A fatigue management workflow has been created for planning and execution monitoring phases. During planning, the engineer can calculate the expected fatigue life of the BHA and optimize for the expected duration of the job. The result can be used to select reliable components with sufficient fatigue life for the job. While drilling, this method enables engineer to continuously monitor the consumed fatigue life of any BHA component and make the decision to replace the tool before a failure occurs downhole. After the job, the consumed life can be recorded in the maintenance system to track the remaining life and decide what preventive maintenance is required.
This innovative workflow has been implemented to manage BHA integrity for medium to high dogleg severity (DLS). The approach to managing fatigue life enables risk mitigation for BHA integrity, pushing kickoffs deeper, shortening the curved sections, and increasing reservoir exposure, including reentry applications. Field cases have proven that the solution provides engineers with a new tool to reduce fatigue failures by predicting expected fatigue life consumed on a job, selecting correct tools, and proactively managing the drilling risks.
Tailored Innovative Bit Technologies Lead to Significant Cost Saving and Performance Improvement in the Ultra-Deep Formation of Tarim Basin in West China
Authors: Teng Xueqing , Zhao Liang , Xu Zhixiong , Cheng Xiaomin , Li Ning , Chen Demin , Feng Shaobo , Zhou Bo , Yang Xiongwen , Zhang Tao , Liu Yu 
Published: August 2016

Abstract
For the ultra-deep ultra-high pressure wells in the Kuqa foreland basin of the Tarim basin in western China, it has been an ongoing challenge for more than a decade to drill through the Cretaceous Bashijiqike (K1bs) formation in a more efficient and economical manner. It is comprised of sandstone and mudstone with abundant natural fractures in the upper K1bs with frequent severe fluid loss occurrence and middle and bottom K1bs are both comprised of highly compacted sandstone, mudstone and siltstone without the presence of natural fractures. In the past, it requires an average of 8, and sometimes up to 16, premium PDC bits and more than 90 days to complete the target interval. This paper discusses the continuous effort in the development and introduction of ongoing bit technologies to drill through the Bashijiqike Formation and the development of methodology that tailors different bit technologies to different sections of the Bashijiqike formation according to drillability characteristics. Dissecting the formation into different sub-zones and matching them with suitable bit technologies results desirable efficiency and significant cost reduction.