bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Performance Modeling of Shale Gas Wells with Non-Uniform Fractures Based on Production Logging
Authors: Pang Wei , Du Juan , Zhang Tongyi , Mao Jun , Di Dejia 
Published: September 2016

Abstract
China is the first country achieving shale gas breakthrough outside the North America. Fuling shale gas play is one of the most successful shale gas reservoirs by far in China. However, production loggings in more than ten wells illustrate that only about one third to one half of hydraulic fractures produces. Meanwhile, the productive fractures contribute differently to the production rate. Therefore, models with non-uniform fracture properties like fracture half-length and distance between fractures are needed to model the production performance considering the production logging information.
In this paper, Models with non-uniform fracture properties are built to take into the consideration of production logging results. In these models, the fractures can be with un-even distance, un-even half-length while combing specific flowing features of shale gas play like desorption, diffusion and stress dependent permeability. Production logging operations of one case well in Fuling shale gas play are reviewed. In order to honor the production logging results, Interpretation models with non-uniform facture and the ones with uniform fractures are compared. Rate and pressure transient data are used to interprete the formation permeability, fracture half-length and stimulated reservoir volume (SRV) by rate normalized pressure (RNP) method. On the basis of understanding of formation properties from rate and pressure transient analysis and non-uniform fractures properties from production logging, production rate and estimated ultimate recovery (EUR) are predicted by the models with non-uniform fractures for the case well.
Results show that only about one third to one half of hydraulic fractures produces and the productive fractures have different contribution to total production rate of shale gas wells. Rate and pressure transient analysis with non-uniform fractures model gets higher formation permeability than the one with uniform fractures model. However, the fractures may have more severe interference between fractures in the non-uniform model and weaken the positive effect of higher permeability on shale gas well's production, or the dominant fractures may affect the less productive fractures adversely. Field applications show that the wells with non-uniform fractures will achieve about 21 percent less EUR than the one with equivalent uniform fractures.
Production performance modeling for shale gas wells with non-uniform factures obtained from production logging is the highlight. The research may partly help the design of horizontal laterals and fractures scenarios.
Reducing Drilling Risks in ERD Wells Through Geomechanical Solutions
Authors: Kaushik Y. D. , Baishya R. C. , Majithia P. P. , Bagchi D. , Pratap Mahendra , Kumar Rajeev , Kumar Devendra , Rao Dhiresh Govind , Singh Hemant 
Published: September 2016

Abstract
In the quest to achieve higher production, extended reach drilling (ERD) wells are planned to be drilled in the Bassein cluster, offshore India, threatened by high risk of wellbore stability after severe hole problems drilling low-angle exploration and appraisal wells. The key to successful drilling is to predict optimal mud weight windows for safe and stable ERD wells with a casing plan to drill the critical buildup section from 30° to 75° through overlying shales. The in-situ stress profile is built and further calibrated with closure pressures obtained during extended leakoff tests and stress testing with the modular formation dynamics tester. Rock mechanical properties are estimated to history match actual failures with predicted failures using the geomechanical model and mud weight used while drilling.
Reported cavings and stuck tool incidents in shale formations are at depth intervals where the estimated breakout mud limit exceeds the mud weight used during drilling of offset wells. There is variation of rock elastic properties like Young's modulus and Poisson's ratio with direction in shale. Intermediate lower-strength coal and shale layers are seen in the Panna sandstone against overgauged hole condition observed in offset wells. Stable mud weights to avoid breakouts are in range of 11.6 to 12.5 ppg depending on well azimuth and deviation across different shale layers. Variations in minimum stable mud weight are in the range of 0.3 to 0.5 ppg based on well azimuth with reference to minimum horizontal stress direction from same platform. Even with depletion of 1.2 ppg in hydrostatic limestone, the minimum mud weight required to safely drill the horizontal section is 8.7 to 8.9 ppg due to lower- strength layers. Well deviation should remain same in the 12.25-in. section to avoid hole cleaning issues in shale. The breakout-mud loss window varies between 1.3 and 1.8 ppg at high well deviation in the 12.25-in. section. The 20-in. casing shoe plan was modified by setting deeper by 100 to 150 m to obtain a higher mud weight window. Lower core recovery at the top of the target limestone reservoir coincides with overgauged hole conditions seen across all offset wells. The local normal fault regime identified against regional strike-slip geological setting.
The modifications resulted in significant reduction of nonproductive time with no lost-in-hole incidents and time savings of 1 week on each ERD well compared to offset wells. The good hole condition made it possible to acquire formation pressure measurements across the field to update the reservoir model and understand the structural connectivity of different target layers.
Flow Assurance During Deepwater Gas Well Testing: When and Where Hydrate Blockage Would Occur
Authors: Zhao Yang , Wang Zhiyuan , Zhang Jianbo , Wang Xuerui , Sun Baojiang 
Published: September 2016

Abstract
The current dominant method to handle hydrate associated problems during deepwater gas well testing is injecting massive inhibitors (e.g. methanol and glycol). This technique is uneconomical and environmentally harmful. A model is established to assess when and where a hydrate blockage would occur in the testing tubing. The characteristics of gas hydrate formation and deposition in the testing tubing are analyzed based on recent published gas-dominated flowloop investigations. The growth of the hydrate film formed on testing tubing walls is modeled. The model is used to estimate the amount of hydrates formed (on the tubing walls) and determine when and where hydrate blockage would occur. Based on the proposed model, a case study is carried out to investigate the effect of gas production rate, water depth, and inhibitor concentration on hydrate blockage development during deepwater gas well testing operations. Hydrates form and deposit more rapidly and the growth rate of the hydrate layer is higher when the gas production rate decreases, and/or the water content and the water depth increase, thus it takes a shorter time for hydrates to block the testing tubing. Conversely, longer time is required for the formation of hydrate blockage. For a typical deepwater gas well (water depth: 1565 m, liquid holdup: 3 %, gas production rate: 45×104 m3/d), it takes about 35 hours for the occurrence of hydrate blockage. Injection of hydrate inhibitors significantly delays the blockage. The study suggests that no inhibitors are required when the well testing operation can be completed before hydrate blockage occurs. Otherwise, the hydrate risk can be managed by injecting small amounts of inhibitors to delay the blockage, rather than keeping the system totally out of hydrate stability region with a high inhibitor fraction. The study suggests a more economical and environmentally friendly hydrate management technique for deepwater gas well testing operations, which can be applied as an alternative to the current total prevention method. The proposed model can be used as a useful tool for flow assurance engineers to estimate hydrate blockage risk and optimize inhibitor injection.
A Shale Matrix Imbibition Model – Interplay between Capillary Pressure and Osmotic Pressure
Authors: Li Xiaopeng , Abass Hazim , Teklu Tadesse W. , Cui Qi 
Published: September 2016

Abstract
High and efficient deliverability of stimulated reservoir volume through a hydraulic fracturing treatment relies on three segments: fluid flow from matrix to the interface between fracture and matrix media, fluid-rock interaction at the fracture-matrix interface, and conductivity of fracture network. Thus, fluids and salt exchange between matrix and fracture network are critical and worth detailed investigation. Moreover, matrix imbibition as an important EOR mechanism has been extensively studied but the focus was mostly given to capillary effect. However, for shale, due to the pore structure and clay content, some physico- or electro-chemical forces at molecular level cannot be overlooked anymore, such as osmosis.
A multi-mechanistic numerical shale matrix imbibition model is developed. The model takes into account dynamic water movement caused by capillary pressure and osmotic pressure as a function of water saturation and salt concentration, respectively. The rock matrix is considered as the mixture of two different components, one with small nano/micro-pores and semi-permeable membrane property and the other having larger meso-pores. The model properly simulates water and salt transportation occurring across the matrix-fracture network contact surface driven by capillarity, osmosis, and salt diffusion. To honor the physics, the salt/ions concentration equation differs from previous work by removing the osmosis component and a new membrane efficiency coefficient is defined and properly incorporated in the model.
Spontaneous imbibition test results were used for matching and validation purposes. The simulation results well explained laboratory high-salinity water imbibition curve, which can be divided into three processes. Initially, a capillary driven imbibition sucks high salt-concentration water into matrix near the matrix-fracture contact surface. However, due to the significant salinity contrast between imbibed fluids and in-situ matrix salinity, a drainage process can be induced. Eventually, as salinity difference decreases and osmosis is weakening, final imbibition stage starts. This model provides a basis for laboratory measurements interpretation and brings some insights to reveal the underlying mechanisms for field post-frac flow-back behavior.
A Robot that Removes Operators from Extreme Environments
Authors: Peerless Ian , Serblowski Adam , Mulder Berry 
Published: September 2016

Abstract
Hydrocarbon exploration and production is moving into increasingly extreme environments as exemplified by the Kashagan field in Kazakhstan. This has high concentrations of high pressure hydrogen sulphide gas, extreme climactic variations, and remote normally unmanned islands that can be difficult to access at certain times of the year. Therefore, the North Caspian Operating Company (NCOC) decided to investigate whether its production operators could work from the safety and comfort of the control room while operating on-site robots.
Sensabot evolved from this challenge. It is characterised by its ability to operate in potentially explosive environments, long intervals between routine maintenance, and the fact that it can operate in walkways that have already been designed for human access.
The Sensabot project was launched in 2010 and has been led by Shell on NCOC's behalf. The Mark 1 Sensabot was delivered in 2011 and contained an array of cameras, gas detectors, a vibration detector and a microphone. Trials of this robot were very successful so the development project was continued resulting in a manipulation arm and Sensabot Mark 2. The latter is now proceeding through the certification process for Zone 1 explosive environments with a view to deployment in Kazakhstan during 2016.
Leaders of upstream oil and gas companies will benefit from an understanding of Sensabot's capabilities and of the implications for improved operational safety. There are also early indications that robots might improve operational efficiency in extreme environments.
Monitoring of Matrix Acidizing by Using Resistivity Measurements
Authors: Ghommem Mehdi , Qiu Xiangdong , Brady Dominic , Al-Tajar Firas , Crary Steve , Mahjoub Alaa 
Published: September 2016

Abstract
This paper is focused around testing a novel concept based on resistivity measurements to monitor acid stimulation operations. A feasibility study was carried out to show the potential success of the proposed concept. A series of coreflooding experiments were conducted at elevated pressure (3,000 psi) and high temperature (65°C) while recording the resistivity and pressure data from taps placed along a rubber sleeve housing the core samples. Results show the ability of the resistivity measurements to track the acid penetration and provide insight on the wormhole morphology. A numerical model was also derived to determine the electrical resistivity while injecting acid and dissolving the rock sample. A comparative study with the experimental results shows that the model predicts the change in the electrical resistivity during acid injection with good accuracy.
It is believed that the proposed concept for monitoring the wormholing process can be adopted in the field with the deployment of the induction tools. A yard test was performed to verify the response of a real induction tool to simulated wormholing features. The results demonstrate the capability of the resistivity measurements to delineate the wormholing zones. The outcome of this novel monitoring concept is expected to provide an unprecedented level of understanding of the depth, the number, and the type of wormholes being created downhole. The interpretation of the wormhole formation and propagation will provide guidance to enhance the operational efficiency and maximize productivity gains along the entire wellbore.
A Chemical Potential Dominated Model for Fracturing-Fluid Flowback Simulation in Hydraulically Fractured Gas Shale
Authors: Fei Wang , Ziqing Pan , Hun Lin , Shicheng Zhang 
Published: September 2016

Abstract
High-clay shale formations could behave as a semi-permeable membrane, thus causing osmotic water molecules flow from low-salinity side to the high-salinity side. This chemical potential dominated flow, we believe, has non-negligible influence on water leak-off and flowback during the treatment of hydraulic fracturing, since there is a considerable salinity difference between the low-salinity fracturing-fluid and the high-salinity formation brine.
In this paper, we present the development of a comprehensive triple-porosity (organic materials, inorganic materials and fracture network), dual-permeability, chemical potential dominated water/gas flow model that uses experimentally determined formation properties to predict the fracturing fluid flowback of hydraulically fractured shale gas wells. The dual-permeability includes the chemical potential dominated flow within inorganic materials and the pressure dominated flow within fracture network. Fracture network is considered as an interconnected continuum embedded in shale matrix, where organic shale is interspersed within vast inorganic shale. The organic material is thus considered disconnected in the entire reservoir. The chemical potential dominated flow model accounts chemical osmosis, capillary and viscous forces.
The water saturation profiles for both osmosis-induced and capillary-induced cases are compared, revealing a region of saturation that effectively is immobile even though irreducible saturation has not been reached. The results indicate that chemical osmosis is a key mechanism for fluid loss during the hydraulic fracturing and should not be ignored under high clay content cases. This work provides a basis for flowback data analysis of hydraulically fractured shale gas wells and also helps define value adding laboratory measurements.
Effect of Well Trajectory on Liquid Removal in Horizontal Gas Wells
Authors: Brito R. , Pereyra E. , Sarica C. 
Published: September 2016

Abstract
A systematic experimental study on two-phase air-water was carried out to evaluate effect of well trajectory on liquid removal in horizontal gas wells. Experiments were conducted in a facility with a 2-in. ID and 62.6-ft. long lateral section and a 41-ft. vertical section, which mimics a horizontal well. Four well configurations were considered; namely, toe-down, toe-up, one-undulation with a sump and one-undulation with a hump. Additionally, different flow conditions were used to simulate the well production as the reservoir pressure depletes. The effect of well trajectory on the liquid removal was evaluated measuring the pressure gradient, liquid holdup, film reversal, and flow pattern.
Experimental results indicate that under stable conditions, toe-up is the best configuration for the displacement of the produced fluids from the toe to the kick-off point. However, at very low gas flow rates, severe slugging is observed in this configuration. Furthermore, for the toe-down, one-undulation with a sump, and one- undulation with a hump configurations liquid loading is observed in both lateral and vertical sections of the well. Consequently, significant liquid accumulation and an eventual slugging condition are observed in the well. It was observed that the measured critical gas velocity to avoid liquid loading is lower than gas velocity at the minimum pressure gradient, indicating that minimum pressure gradient criterion is not enough to determine whether the well will be under stable or unstable conditions. Finally, toe-down configuration presents the largest liquid accumulation in the lateral section, indicating lower efficiency to remove liquids from the toe to the kick-off point.
Geopolymer Composites as Efficient and Economical Plugging Materials in Peanuts Price Oil Market
Authors: Salehi S. , Ali N. , Khattak M. J. , Rizvi H 
Published: September 2016

Abstract
Optimization of well construction process by utilizing more economical and efficient materials can help in reducing overall well expenditure. Plug and Abandonment (P& A) process can be very costly depending on well's situation and materials used for P&A. Plugging materials for abandonment needs to have pumpability, good shear bond, and compressive strength and reasonable shrinkage. Previous research on application of geopolymers in oil/gas wells was mainly unsuccessful due to failure to achieve a reasonable thickening time. The results presented in this work propose different mixtures of Class F fly ash Geopolymer binder with controllable thickening times in temperatures up to 250 °F. Mixtures were tested for unconfined compressive strength (UCS), shear bond strength, shrinkage, thickening time, durability and contamination. The Geopolymer mixtures in this work compose class F fly ash rich in Silicate, Aluminum and have elements of Potassium, Calcium, Iron, Sodium and Titanium. Mixture of Sodium Hydroxide and Sodium Silicate was used to activate the Fly ash mixtures. Geopolymer mixture designs tested in this work showed high compressive strength, shear bond strength, low shrinkage and suitable thickening time for applications in well abandonment purposes. In addition to good resistance to Oilbased Mud (OBM) contaminants, these alternative P&A materials can be produced cheaper with less environmental impact which fits well for applications in the oil and gas well cementing.
Flow Rate Estimation of Downhole Leaks Using Acoustic Sensor Array
Authors: Lu Yinghui , Walters Darren , Hill Freeman 
Published: September 2016

Abstract
Well integrity is becoming a key area of focus for most operators during the entire well life cycle. Acoustic conformance-monitoring systems have been developed to detect undesired leaks in terms of depth and radial location and to estimate leak flow rates, enabling operators to assess the severity of the leak and to plan remedial action. If the leak flow rate were substantial based on a given threshold, the remedial action would be scheduled with high priority; otherwise, repair work would be deferred to a suitable maintenance time.
This paper presents a systematic statistical methodology to estimate leak flow rates using data acquired by an acoustic sensor array. The first stage of this methodology is data-level fusion through the beamforming technique, in which all signals acquired by an array of acoustic sensors are fused into a new signal. The second stage consists of feature-level fusion, in which representative and distinct features are extracted from the fused signal to construct the feature space. The third stage is decision-making, in which a statistical model is fitted in the feature space and then used to estimate flow rates in the sense of probability.
A series of experiments was conducted in which a variety of leak flow rates were simulated with various combinations of orifice sizes and differential pressures in various leak scenarios. A low-dimension, third-order logistic regression model was demonstrated that can be fitted to the data and used to effectively separate small/large flow rates (90.0% specificity and 91.7% sensitivity).
International Regulations and Compliance for Relief Well and Blowout Contingency Planning
Authors: Szemat Vielma W. E. , Mosti I. , Gallagher L. , Nergaard K. 
Published: September 2016

Abstract
Several countries have introduced new requirements to ensure that the well design has been evaluated for all well control possibilities, including drilling a relief well. However, without a single global standard, different approaches have been taken into consideration, and this situation merits a review of current legislative mandates for relief well planning (RWP) and/or blowout contingency planning (BCP).
Primarily through open source literature, a compilation of legislative requirements is provided, giving a short history of the legislative change that preceded relief well and blowout contingency planning as a requirement and noting specific technical requirements. The legislative review shows that RWP and/or BCP are becoming more prevalent for operators when seeking permission to drill.
A more detailed overview of the NORSOK D-010 Rev 4 standard (herein called NORSOK) is given because this is considered the most mature existing standard and is often used as a guideline by others. Based on the requirements in the NORSOK standard, an overview of the cross-disciplinary workflow necessary to model a blowout and relief well contingency plan is suggested: data gathering, relief well design, and dynamic multiphase simulation to determine worst case discharge and dynamic kill requirements to regain control of a blowout. The cross-disciplinary workflow for blowout and kill simulation modelling can lead to misinterpretation of the objectives. Drilling engineers are typically tasked with producing a BCP, but reservoir and/or production data drive the workflow.
This paper provides current regulations for RWP and BCP that operators can use as quick reference and compare and contrast for their ongoing or future operations, ensuring that compliance and maximum safety standards are adhered to at all times.