bluuebunny/crossref_metadata_2025_split huggingface dataset:
Handling Missing and Corrupted Data in Waterflood Surveillance, Using Reservoir Linear Characterization Models
Authors: Attar Atheer Al , Hughes R. G. , Hassan Omer F. 
Published: October 2016

Abstract
Oil field data are not always accurate and complete. According to Nobakht et al. (2009), corrupted and missing data costs the industry $60 billion annually. Unless extreme caution is taken to collect data, every dataset is expected to have at least 1-5% error from different sources i.e. human error, measurement setup error or measurement equipment malfunction. The main issue when dealing with missing and corrupted data is limited understanding of our data behavior. Better understanding means improved decisions will be made to remedy missing and corrupted data. Generally two methods are used to deal with the missing data: 1- Dropping missing intervals; 2- Estimation of expected missing point values. In this paper, both methods will be tested and applied on missing production and injection rates in waterfloods projects. A simple reservoir model was used to calculate the expected value for the missing values of the production rates, namely the Resistivity Model (RM) by Albertoni (2003). Reverse modelling was utilized to estimate the missing values for injection rates. Several cases were simulated with two missing ratios: low (15%) and high (30%) in both the production and injection data. Missing points were generated in the datasets in the form of four patterns (Arbitrary, Monotone, Multivariate and Modified Multivariate). The missing data locations were selected in a Monte Carlo-like manner and results were averaged from 400 realizations for each pattern. An error rate was obtained for each pattern and missing data from both injection and production rates were considered. The dropping method showed a larger error propagation rate when the modified multivariate mode is in effect. This pattern is expected to happen when there is a systematic accident or problem in the rate measurement devices. Thus, it takes time until the system can be returned to normal measurement. The least amount of error occurs when there is arbitrary missing data that could happen at any time. The recommendation here is that dropping is not an appropriate method if there is more than 3% missing data. The value of R2 approaches 60% quickly once the amount of missing data hits 2% for all patterns. This also helps explain the reasoning behind using only full data sets for a method such as RM. For a case with 15% missing data with data missing from both the injection and production, an R2 value of 0.87 was obtained using the method of imputation presented. This work found that missing more than 6% of the data is the limit for dropping data since the model R2 drops very fast when the amount of missing data is more than 6%.
Application of Subsea Demulsifier Chemicals to Reduce Heavy Oil Emulsion Viscosity and Enhance Production in the Pyrenees Development
Authors: Gilbert M. L. , Morley D. A. , Elliott P. A. 
Published: October 2016

Abstract
The Pyrenees development is located offshore Western Australia, and has been producing since 2010 under the operatorship of BHP Billiton Petroleum. Six heavily biodegraded, low GOR oil fields are developed by 19 horizontal production wells with reservoir sections up to 3000m long. Each field has between 1 and 6 gas lifted production wells connected by separate production and test flowlines to a Floating Storage Production and Offtake (FPSO) vessel. As field water cuts progressed above 10%, an increasing deviation between predicted and actual flowline pressure drop was observed and indicated the formation of emulsions in the wells production tubing and flowlines. The additional flowing pressure loss and consequent reduction in production rates formed the basis for a debottlenecking project to treat subsea emulsions.
After identification of a suitable demulsifier chemical through laboratory testing, chemical treatment was initially undertaken via injection at the subsea manifolds. Initial demulsifier field trials yielded a 4% increase in field oil production.
In an attempt to realise further pressure drop reduction, the opportunity for downhole injection at each well was investigated. As downhole chemical injection had been initially designed for scale inhibitor, flow assurance studies were performed to ensure repurposing the downhole lines would not result in an elevated calcite scaling risk in subsea equipment.
Field implementation of downhole chemical injection across the available wells resulted in an additional 18% field oil production uplift, with individual wells achieving up to 50% increase in drawdown and 58% increase in liquid production. Additional benefits attributed to downhole demulsifier injection include improved gas lift efficiency and stabilised flow regimes and pressures observed at the downhole gauges and topsides risers.
This paper provides a unique case study in opportunity identification and multifaceted problem solving to significantly and safely debottleneck production. An innovative solution was found by relocating the injection location and repurposing existing topsides and subsea equipment with very low additional capital investment. The lessons and processes used in this project may be carried across to other existing fields and facilities to assist identifying and resolving related flow assurance bottlenecks.
What We Have Learned on Shale Gas Fracturing During the Past Five Years in China
Authors: Yonghui Wang , Zhuhong Tian , Lifeng Yang , Xingming Yan , Xinbin Yi , Haibing Lu , Yaoyao Duan 
Published: October 2016

Abstract
Scale development of shale gas in North America has greatly stimulated the enthusiasm of China. Since July 30, 2010 the first shale gas well fracturing, more than 300 wells have been fractured in the past five years in China, an average post-frac production is more than 6E4m3/d for one well. Technology include pre-frac evaluation, the methods of fracturing design, fracturing materials, tools and equipment, gas factory workflow and quality control system has formed.
Basis on the study following recognition can be drawn: ①natural fracture distribution、stress difference and fluid viscosity are the key factors to create the complex fracture; ②geological engineering integration concept has been implemented and application successful; ③formulated the principle to improve SRV+3C (complexity, connective, conductivity), design method of shale gas reservoir stimulation has formed; ④formed including of transverse fracture to the horizontal wellbore set, PNP multi-stage fracturing, "the 3 big 2 low 1 small" (Large amount of liquid, proppant, high injection rate. Low fluid viscosity, sand concentration. Small diameter particle combination proppant) design, real-time quality control techniques, and multi-well simulfrac/zipperfrac technology, gas factory workflow, etc.; ⑤ construction capacity and parameters have reached the normal level of North America. Horizontal lateral up to 1000-2000m, single stage 60-100m, single well stages up to 25; For one stage fluid volume is generally 1600-2200 m3, proppant is normally 60-170t/stage, pumping rate is 8 -16 m3 / min; Usually for zipper-frac 2-4 stages can be finished in daytime, and 6 stages for simul-frac, post-frac production is from 6 to 55 (E4 m3/d) for a single well.
In this paper, not only successful experience on shale gas well fracturing are presented, but also some challenges, such as casing deformation, frature discription, water shortage etc.
Stimulation in High Water-Cut Wells: Treatment Optimization Using a Fluid Placement Model
Authors: Bhatnagar Ankit , Eoff Larry 
Published: October 2016

Abstract
This work discusses application of an advanced placement model for optimizing stimulation treatments in high water-cut wells. Stimulation treatments in high water-cut wells are challenging because they can lead to an undesired increase in water production. Associative polymers have been successfully used as diverters for addressing this challenge, and effective treatments have been performed based on experience and guidelines. However, further optimization of such treatments can be achieved using fluid placement models.
Model-based treatment design has been described previously but has not been comprehensively applied for diversion by associative polymers. In this work, a transport model was developed for relative water permeability reduction by associative polymers and diversion of stimulation fluids in the pay zone. The model accounted for the mass transport and adsorption of the polymer in the formation. The transport model was integrated into a near-wellbore (NWB) fluid placement model to simulate fluid distribution in a heterogeneous layered reservoir and the effect on total skin, production/injection profiles, and surface/bottomhole pressures (BHPs) during the treatment.
The paper describes case studies based on actual field treatments to demonstrate the application of the integrated model for optimizing stimulation treatments. Acid-to-diverter stage volumes, number of diverter stages, polymer concentration, and injection rates are identified as important design parameters. Based on model results, it is observed that polymer placement results in increased total skin in water-bearing zones, leading to lower post-treatment water production. Further, the optimum number and volume of diverter stages for effective diversion vary with injection rate and are governed by the non-equilibrium polymer adsorption behavior and the self-diversion effect during placement. It is concluded a single treatment design might not be suitable across multiple wells, and well-specific optimization of the pumping schedule is necessary. Because multiple parameters affect the treatment, simultaneously leading to results that are not intuitive, the placement model should be used for the treatment design.
This paper discusses application of an advanced fluid placement model, which provides insight into the diversion by associative polymers during stimulation treatments. The model is useful for optimizing stimulation treatments in wells with high water cut and reducing costs associated with undesired water production.
Numerical Modeling for the Prediction of Residual CO2 Trapping in Water-Wet Geological Porous Media
Authors: Jahan Farjana , Ahmed Shakil , Hossain Mofazzal , Iglauer Stefan 
Published: October 2016

Abstract
Residual trapping of CO2 has been identified as a reliable and rapid way to dispose large CO2 quantities. Several experimental investigations have been completed where residual trapping in sandstone was measured; these programmes identified that initial CO2 saturation and rock porosity are significant parameters which influence the residual saturation and thereby residual trapping capacity and effectiveness. In order to further improve fundamental understanding a computational tool need to be developed with which residual CO2 saturations can be predicted.
Pore-scale two-phase fluid flow simulation is performed based on the integration of x-ray micro-tomography images (which provide a detailed description of the rock's pore space) and Navier-Stokes equations. X-ray micro-tomography (approximately (6µm)3 voxel size) images of F42 sand pack were used. The extracted pore morphology of each medium was obtained by segmenting the images based on their greyscale contrast using image processing software AVIZO Fire. These binary images were converted initially into surface and volume meshes which were then fed into a commercially available computational fluid dynamics code (ANSYS-CFX). Three dimensional transient, laminar flow fields were obtained by solving the continuity and Navier-Stokes equations using an Eulerian-Eulerian multi-phase flow approach. To incorporate the effect of capillary forces, free surface model was used which solved the pressure gradient at the interface correctly. The model assumes isothermal condition with no mass transfer between the brine and CO2. The inlet and outlet boundary conditions include CO2 flow rate and the pressure respectively. We simulated the drainage condition in this paper. Approximately 1.5 million tetrahedral elements were used to generate volume mesh, and the convergence criterion for all variables was set to 10-3. Initially all pore space was filled with brine, and then CO2 was injected from one inlet side at constant flow rate, obtained from the experiments. When the system was at connate water saturation, we stopped our simulation. The residual saturation depends on the flow rate of super critical CO2.
The computations described here are a rapid, cost-effective and can reveal vital information for the planning of carbon geo-sequestration projects and associated risk and capacity assessments.
Novel Cementing Solutions to Impede Lost Circulation with Highly Crush-Resistant Lightweight Cement System and Engineered Fibers
Authors: Putra T. , Steven A. , Wedhaswari V. R. , Awalt M. S. , Natanagara B. B. , Pasteris M. , Jaffery M. F. , Sheikh Veisi M. , Rudiantoro A. 
Published: October 2016

Abstract
Seguni field and Sejadi field are smaller regions of Sepinggan field in offshore of East Kalimantan, Indonesia, which were drilled and developed by the operator since 1977. Seguni-V (redrilled well) was prognosed to encounter several depleted sandstone formations with reduced pore pressure due to produced hydrocarbons. Consequently, the utilized drilling fluid density was set as low as reasonably practical and this methodology had successfully prevented any lost circulation event until the total depth (TD) was reached. Nonetheless, the risk of losses were greater in the cementation phase of the 3 1/2-in tubing due to long column of cement (&gt;7000 ftMD) required. Therefore, the challenge was to reduce the cement slurry density that still can achieve a required compressive strength within timely manner. The reduced slurry density was also predicted to be instable downhole due to the immense bottomhole pressure, which might crush the conventional cenospheres in the slurry as lightweight materials and result in an increase of downhole slurry density. Therefore, to minimize the risk of induced lost circulation caused by slurry density increase, a novel lightweight material with highly-crush resistant property was proposed. The result of the job with this cement system was satisfactory with no losses occurred and the targeted intervals were covered with good cement.
Sejadi field, on the other hand, had experienced losses while drilling, from seepage losses which were commonly found, up to 170 bbl/hr of loss rate at one of the wells in the field. A particular lost circulation case with persistent loss rate into depleted formations was observed at Sejadi-X well. 728 bbl of synthetic based mud (SBM) had been lost into the hole when a loss rate of &gt;40 bbl/hr was encountered while drilling 8 1/2-in open hole (OH) section. The loss rate could not be reduced even after spotting three times of 30 bbl conventional lost circulation material (LCM) pill and had cost significant volume of SBM and LCM amount lost to the formation, as well as 2 rig days spent in attempt to cure the loss. The study of the previous failure on similar problems in the neighboring well led to the solution proposal to use engineered, optimized fiber in cement slurry for lost circulation plug. The result was prominently effective and drilling operation could be resumed to total depth.
This paper describes the features, case histories, challenges, field applications, as well as the acknowledged results of mentioned technologies. Lastly, this paper also introduces a mutualistic technical feature when the two technologies are combined to both prevent and mitigate lost circulation.
Mathematical Model and Experimental Study on Drill-In Fluid Loss Control and Formation Damage Prevention in Fractured Tight Reservoir
Authors: Xu Chengyuan , Kang Yili , Li Daqi , You Zhenjiang , Luo Yaohua 
Published: October 2016

Abstract
Drill-in fluid loss is the most important cause of formation damage during drill-in process in fractured tight reservoirs. Lost circulation material (LCM) addition into drill-in fluid is the most popular technique for loss control. However, traditional LCM selection is mainly performed by trial-and-error method, due to lack of mathematical models. The present work aims at filling this gap, by developing a new mathematical model to characterize the performance of drill-in fluid loss control using LCM during drill-in process of fractured tight reservoirs. Plugging zone strength and fracture propagation pressure are the two main factors affecting drill-in fluid loss control. The developed mathematical model consists of two sub-models, i.e., the plugging zone strength model and the fracture propagation pressure model. Explicit formulae are obtained for LCM selection based on the proposed model, in order to control drill-in fluid loss and prevent formation damage. Laboratory tests on loss control effect by different types and concentrations of LCMs are performed. Plugging pressure and total loss volume are measured and compared with modeling results. Effects of LCM mechanical and geometric properties on loss control performance are analyzed, for optimal fracture plugging and propagation control. Different combinations of acid-soluble rigid particles, fibers and elastic particles are tested in order to generate a synergy effect for drill-in fluid loss control. The derived model is validated by laboratory data.
High Performance Water-Based Mud HPWBM: Turning Old Ways into New Opportunities
Authors: Mahrous Ramy , Vader Ronald , Larreal Enrique , Navarro Raul , Salmelid Bjarne , Honey Alastair , Weir Malcolm , Lammers Gert , Rijnen Peter 
Published: October 2016

Abstract
For decades, wells targeting the Rotliegend reservoir in the Southern North Sea Basin have been drilled using conventional water-based mud (WBM) in the top hole section and oil-based mud (OBM) systems throughout the remaining sections of the well. The standard well design generated high waste disposal costs onshore and offshore, particularly with regard to OBM waste. This study evaluates alternative fluid systems to help reduce disposal costs for the operator.
As part of the operator's environmental improvement strategy, the operator and fluids provider team identified potentially significant waste disposal cost savings for an onshore trial. Using a WBM system for drilling top holes as well as through the lower sections could result in cost savings through the reduction of top hole fluid dilution as well as a reduction in waste disposal costs.
A high-performance water-based mud (HPWBM) system with similar performance to an OBM system was proposed as part of a trial to demonstrate these potential savings in disposal costs for an onshore well.
The field trial was a great success compared to conventional fluid systems and methodologies. The well was drilled 11.6 days ahead of schedule and 20% under the planned budget. The time vs. depth curve was on par with what was expected when drilling with an OBM system.
The HPWBM system created a saving of &gt;5% of the total well cost and it was 16% less expensive than conventional fluid systems. A further saving of 2.5% of the total well cost was identified for future onshore/offshore applications of the HPWBM system. It was also theorized that a further reduction in waste disposal costs could be realised in offshore operations.
The field trial was based on a basic onshore well trajectory as a proof of concept. Upon the success of using HPWBM in the basic well, more challenging onshore as well as offshore applications would be examined which have the potential to double the cost savings generated.
This novel approach of using an environmentally acceptable HPWBM system in the Southern North Sea Basin can offer significant cost saving opportunities with regard to waste management for both onshore and offshore wells compared to conventional WBM and OBM systems.
Modelling of Slow Fines Migration and Formation Damage During Rate Alteration
Authors: Yang Y. , You Z. , Siqueira F. D. , Vaz A. , Bedrikovetsky P. 
Published: October 2016

Abstract
Fines migration involving particle detachment in reservoirs often leads to severe permeability damage. It is the consequence of straining of the detached fines in relatively narrower pore throats. Many laboratory coreflood tests indicate that the time of permeability stabilisation can reach hundreds or thousands of pore volumes injected. However, the classical filtration theory assumes that the mobilised fines are transported by the bulk of the carrier fluid, thus the permeability stabilises after one pore volume injected. The current paper attributes the stabilisation delay to the slow drift of the released fines close to the rock surface. We propose the system of flow equations for fines migration in porous media taking into account the velocity of particles lower than that of the fluid. An analytical model for one-dimensional flow with particle mobilisation and straining during piecewise increasing flow rate is obtained. The laboratory data are in good agreement with the results of mathematical modelling. The effective particle speed is 500-1000 times lower than the water velocity.
Integrated Innovative Technology Saves 354 Rig Days in an Infill Drilling Campaign - A Case Study from Bohai Bay, Northern China
Authors: Ma Yingwen , Zhang Binqi , Liu Feng , Li Junbao , Zhang Bo , Wu Kai , Wang Fei , Xu Tianyun , Yu Xiaoning , Zhang Hongyong , Xu Bing 
Published: October 2016

AbstractField X, locating in Bohai bay, Northern China, was started to develop in 1999 as Phase 1, relying heavily on directional wells. Since 2013, in order to further increase the final recovery rate, this complex fluvial reservoir oilfield has stepped into Phase 2, with a new infill drilling campaign involving 109 wells, mostly horizontal wells.Because of the limitation of the authorization for expenditure (AFE), the predominant effort for this infill project was to increase the drilling efficiency. Therefore, it was requested for all the relevant parties to cooperate to enhance as much as possible drilling in a safe manner. Several risks were identified during the pre-drilling comprehensive assessment: Well collision risk at the top section.Achieve sufficient dogleg severity (DLS) while keeping high rate of penetration (ROP) under unconsolidated sand environment.Bottom water existed due to long-term production of this infill project.To address the above technical challenges, an intergraded innovative approach has been explored by operator and service companies: Multiple preventive and mitigative measures have been applied to minimize the anti-collision risk, such as Gyro surveying on offset wells, shutting down high risk offset wells and casing monitoring, etc.Fit-for-purpose rotary steerable systems (RSS) were used, including the point-the-bit RSS and the hybrid RSS (combining point-the-bit and push-the bit steering) based on the DLS requirements and the previous drilling practices."Distance-to-boundary (DTB)" technology was used to keep optimal distance to target boundary in order to delay the onset of the bottom water and avoid exit from the reservoir, which would result in costly sidetracks.By using this integrated innovative approach, drilling efficiency has been increased significantly in a safe manner. As a result, 354 rig days have been saved (including drilling and completion only) which represent an improvement of 21.8% compared with the original AFE. Converted to sum, it was an 89.54 million USD reduction. In addition, by the help of precise trajectory placement for the lateral section, the scheduled production rate was surpassed by 37% with 2.5% water cut only as of Mar-2016.This exemplary case demonstrated how an integrated approach can help to increase drilling efficiency and save budget in an infill drilling campaign. The authors believe that it could be adopted by other similar project, who is seeking for higher input-output ratio under the current oil/gas environment.