bluuebunny/crossref_metadata_2025 huggingface dataset:
A Holistic Approach to Rank Unconventional Reservoir Prospects led to Pakistan's First Successful Shale Formation Testing
Authors: Shah Syed Muhammad Usman , Araque-Martinez Aura N. , Ahmad Naveed , Ali Rahmat , Chaudhary Muhammad Saqib , Abbas Javed
Published: February 2022

Pakistan holds significant volumes of unconventional hydrocarbon reserves. In 2013 EIA report, the Sembar Formation of the Lower Indus Basin has 101 Tcf shale gas with 5.8 billion barrels shale oil resource as the risked & technically recoverable hydrocarbons over an area of about 81,000 km2. However, the EIA report has highly risked the prospective areas and the likelihood of development success. Thus, the main barrier for unconventional reservoirs development in the country is to reduce the associated uncertainty in a more rigorous manner and to decide, if and where to plant a flag in this vast area. A robust integrated approach was used to delineate and rank the unconventional reservoir prospect of Shale Gas, Shale Oil, and Tight Gas of Upper, Middle, and Lower Indus Basin of Pakistan by using multi hierarchy Shale Analysis Framework. This workflow spans the lifecycle of unconventional resource development by integrating petrophysical modeling, lab data, geologic and geophysical modeling, geomechanical modeling, stimulation modeling, drilling, reservoir and production engineering, and project management. Each of the workflow components is weighted as a function of their relative importance, and prospects in the study area are preliminary ranked according to how well they fulfill the criteria. Finally, the pilot area was selected/ranked by exhaustive uncertainty analysis using reservoir simulation and integrated with economic indicators such as Net Present Value (NPV), Return on Investment (ROI) & Rate of Return (ROR).

Initially, 27 prospective unconventional focused areas were identified and ranked among Upper, Middle & Lower Indus Basin. The top-ranked areas belong to the Sembar Formation of the Lower Indus Basin, in which further detailed assessment was carried out by extensive Shale Analysis Framework. Finally, the pilot areas were categorized based on integrated uncertainty and techno-economic evaluation. Based on outcomes, the top pilot area was tested by a mini-frac job as the first step. The Formation was successfully broken down within the estimated pressure range and produced hydrocarbons during the flow back period. The adopted framework proved to be successful in Pakistan's first shale formation testing and helps to reduce the number of appraisal or experimental wells needed to evaluate the resource potential and shorten the field development planning cycle and/or maximize the economic value of the resource via an efficient integrated approach.
Aramco Nano Permeameter ANP: A New Laboratory Technology for Accurate and Efficient Measurements of Stress-Dependent Source Rock Permeability
Authors: Liu Hui-Hai , Zhang Jilin , Boudjatit Mohammed
Published: February 2022

In an unconventional reservoir, rock matrix has a much larger storage capacity for hydrocarbon and significantly lower permeability than the natural and hydraulic fractures. It acts as a bottleneck for hydrocarbon flow from the reservoir to the production well during production and is a key parameter for controlling the well performance over a long period of time. A new laboratory technology is developed to accurately and efficiently measure the matrix permeability.

We have developed the Aramco Nano Permeameter (ANP), a new laboratory technology for measuring the stress-dependent source rock permeability. While the conventional laboratory methods can only measure one permeability data point with one test run, ANP, based on the nonlinear solution to the gas flow equation, measures the rock matrix permeability for a non-fractured sample as a function of stress using a single test run and thus is very efficient.

Permeability as a function of pore pressure at a given confining stress is measured with ANP for several Eagle Ford rock samples without fractures. The permeability curve shows complex behavior: permeability initially decreases with increasing pore pressure, as a result of Knudsen diffusion effect, and then increases with pore pressure owing to the mechanical deformation. The measured permeability curves are verified by comparing them with permeability values measured with other methods for selected pore pressures. The high measurement efficiency of ANP is also demonstrated.

In summary, ANP is a laboratory method that is based on a theoretical idea that is significantly different from those currently used by the industry and thus provides a high measurement efficiency that the conventional methods cannot achieve.
Machine Learning Empowered Well Placement in a Large Unconventional Tight Gas Field in China
Authors: Yu Ting , Wang Xiangzeng , Carrillat Alexis , Du Kuifu , Liang Quansheng , Grossmann Tino , Zhu Ming , Wang Gaige , Feng Lijun , Xue Jie , Quan Min , Saraiya Rasesh Krishnaraj
Published: February 2022

An undisclosed tight-gas field produces gas from a large heterogenous fluvial reservoir with limited well control in margins and appraisal areas, as well as sparse advanced logs (formation micro-imaging, magnetic resonance, or sonic tools, etc). The principal goal of this study is to provide a novel solution using machine-learning (ML) techniques to predict sandstone distribution and to some extent automate the process of optimizing well placement. This workflow overcomes low data quality, scaling, and inconsistency, and builds the bridge between geoscience and artificial intelligence (AI) software platforms.

This newly proposed solution provides a combination of ML and geological studies to optimize well placement. The key steps of this technology are:

Use unsupervised seismic waveform classification together with well logs to define sand body distribution and generate a reservoir risk map to support well planning. Construct a 3D grid with multiple variables to extract and integrate well logs and seismic attributes from existing 2D seismic lines for data organization and analysis. Set up the data transform mechanism to unlock restrictions of data analysis between subsurface domain and AI software platforms. Test multiple ML algorithms by carrying out a deep search to find seismic attributes that are the most sensitive to reservoir parameters and form the decision trees for quantitative analysis. Evaluate and select the high-performance results, export them into the subsurface software platform, and make the final property model available for integration and visualization to support well placement.

Multiple tests have been completed to date in this gas field, and the results showed that the technique can improve well placement, add potential reserve and also improve the efficiency of the workflow by reducing the execution time by 240 times. The results provide solid support to achieve more reliable and accurate well placement.

This new solution generates an improved reservoir risk map with flexibility of using many secondary variables or their combinations. It produces results with higher resolution and focuses on improving efficiency. It also reduces turnaround time and increases collaboration over conventional approaches by improving the accuracy of fast predictions as the data flow enriches the database rapidly, which unleashes big data potential. This innovative solution can be applied to other projects especially ML empowered well placements in complex geological settings.
A Novel Semi-Analytical Model for the Multiwell Horizontal Pad with Stimulated Reservoir Volume
Authors: Chu Hongyang , Ma Tianbi , Gao Yubao , Zhu Weiyao , Lee John
Published: February 2022

Recently, there have been many attempts to model the stimulated reservoir volume in unconventionls. However, most researches only focused on the intersecting hydraulic or natural fractures and the effects of stimulated reservoir volume are ignored. In this study, we developed a new method that uses an effective semi-analytical method to model the stimulated reservoir volume in unconventional reservoirs.

Large-scale hydraulic fracturing not only forms hydraulic fractures but also activates a large number of natural fractures in the near-well region. To the best of our knowledge, most of the multiwell horizontal pad modeling methods ignore the physics of stimulated reservoir volume. Our semi-analytical model has the ability to simulate the behaviors of a multiwell horizontal pad with irregular shaped stimulated reservoir volume and impermeable boundary. Results show that the transient pressure behavior of the multiwell horizontal pad with stimulated reservoir volume is significantly different from that of a single isolated well. The linear flow among wells, the pseudo radial flow of multiwell in stimulated reservoir volume, and transitional flow, and final pseudo radial flow of multiwell correspond to completely different transient pressure response. The high flow ability in stimulated reservoir volume means a faster rate of pressure diffusion and it lead to the appearance of these flow regions in advance. The results also confirm that as the scale of stimulated reservoir volume increase, the flow duration influenced by the stimulated reservoir volume is longer. The stimulated reservoir volume and offsetting wells makes the pseudo-radial flow feature insignificant. The pressure and the pressure derivative exhibit a gradual rise feature. For the pseudo-radial flow in stimulated reservoir volume, the horizontal line value is related to the total production of the well pad. For the unstimulated region, this value is also related to the mobility ratio.
Comprehensive Study on Newly Developed Diffusion-Desorption Models Based on Knudsen and Langmuir Models in Tight Gas Reservoirs
Authors: Alkuwaiti Hamda , Belhaj Hadi , Aldhuhoori Mohammed , Ghosh Bisweswar , Fernandes Ryan
Published: February 2022

Fluid flow in unconventional porous media is extremely complex due to the many physical processes and forces that governs fluid flow, such as diffusion, inertia, viscous flow, and sorption. Furthermore, modeling fluid flow in poor porous media often disregards the mentioned forces, assuming viscous transport is the predominant controller. This work introduces a new comprehensive flow model suitable for tight unconventional reservoirs, including viscous, inertia, diffusion, and sorption forces, to account for fluid transport in the three scales. The new model addresses 1-D linear flow in tight unconventional reservoirs and has been mathematically derived and numerically solved using MATLAB software and tested against a synthetic case study. The new models have been numerically solved and analyzed using synthetic data with previously published models that cater to the same phenomena and analyzed. In addition to studying the flow regimes effecting gas flow in porous media. It has been observed that the diffusion system becomes more prominent in regulating flow velocity with low permeability of the formation rock and low viscosity of the flowing fluid. Additionally, as a result, the sorption mechanism contribution to the flow increases with low permeability of the medium and low viscosity of the flowing fluid as it affects the concentration of gas, leading to release gas from being trapped in pores and rock surfaces.
Novel Multi-Stage Fracturing Sand Control Technology to Improve Completion Efficiency, Early Production and Reduce Well Cost
Authors: Gomez Ricardo , Khan Parvez , Stolboushkin Eugene
Published: February 2022

High pressure stimulation of tight sandstone formations is occasionally combined with flowback of proppant and formation sand during the onset of production. This is generally attributed to characteristics of unconsolidated sandstones and their response to high pressure hydraulic stimulation. This brings an additional challenge to openhole multi-stage completion systems that now require a filtration mechanism as part of the completion design, to introduce a sand exclusion technology alongside the multi-stage ball activated frac sleeves.

A novel openhole multistage fracturing system was developed combining the operational efficiency of ball activated frac sleeves with sand control efficiency of multi-membrane filtration sand screens. This combination of technologies deliver a robust completion design and a unique intervention-less solution to enable stimulation at high pressures and provide sand exclusion on production. The system comprises of a series of incrementally sized high strength disintegrating frac balls to activate and close stimulation frac sleeves while simultaneously also opening production sand control screens. The design allows for several production sand control screens in one stage to maximize reservoir contact for unrestricted production. The system allows to efficiently complete the frac treatment and start sand-free production of the well without any intermediate manipulation of downhole tools with coiled tubing (CT) or wireline.

This technology brings substantial value by not only early sand-free production, but also flexibility to add additional sand screens within the stage without compromising stage count. The intervention-less design of the tools eliminates the need for coiled tubing (CT) manipulation of downhole tools and hence associated high intervention costs. Keeping in mind the increased need of high-pressure stimulation for unconventional and tight reservoirs, the system is designed to 15,000 psi rating. The sand screens are designed to be isolated from stimulation pressure while maximizing inflow area without compromising on sand control. Further, to enable full efficiency, the system includes high-strength disintegrating frac balls to enable an early production of the well.

This paper encapsulates the design, functionality, and development testing of the intervention-less multistage fracturing sand control system. This novel technology is designed keeping in mind operator challenges associated with high cyclic stimulation pressure on completion tools, undesirable well intervention and associated high production costs.
The Impact of Horizontal Bedding Plane Fractures on Reservoir Fluid Production in Shale Oil Plays with High Pore Pressure
Authors: Arias Ortiz Daniela , Klimkowski Lukasz , Finkbeiner Thomas , Patzek Tadeusz W.
Published: February 2022

Massive hydraulic fracturing stimulation generates complex induced fracture systems in shale reservoirs. The complexity increases in mudrock plays characterized by overpressure and associated small differential stresses. Such conditions favor interactions between induced vertical hydraulic fractures and mechanically weak bedding planes. When these planes delaminate easily, they may hydraulically stimulate large horizontal fracture components. In such situations, weak bedding planes are critical during hydraulic fracture propagation, impacting the fracture geometry and associated hydrocarbon production. We examine the effect of stimulated mechanically weak horizontal bedding planes on reservoir fluid production in multilayered mudrock plays distinguished by high pore pressure. We propose two idealized but viable geometries (‘fracture scenarios’) reported to occur in some overpressured shale plays. Our reference scenario comprises only vertical and planar hydraulically induced fractures. In the second geometry, we add stimulated horizontal bedding plane fractures that intersect the vertical hydraulic fractures. Next, we integrate the predetermined fracture geometries into a commercial reservoir simulator (CMG-IMEX) and assess the wellbore flow performance. Finally, we perform sensitivity analyses on horizontal fracture closure-mechanism, position and number of horizontal fractures, and reduced vertical fracture permeability. The results reveal that large horizontal fractures compromise hydrocarbon production. We conclude that horizontal fracture compressibility and vertical hydraulic fracture permeability are critical parameters during reservoir simulation. Compared with the reference scenario, the unpropped (i.e., highly compressible) and large stimulated horizontal fractures may reduce the initial oil production by 13% and the cumulative oil production at 15 years by 10%, assuming the highly conductive vertical hydraulic fractures. In contrast, horizontal fracture propagation results in shorter and narrower vertical hydraulic fractures. Thus, the lowered vertical hydraulic fracture conductivity predicts that initial oil production may decline by up to 77%. Finally, we show that vertical and planar hydraulic fractures geometry is not always an accurate assumption. This assumption may lead to an overestimation of hydrocarbon production during shale reservoir simulation studies. Our unique reservoir simulations show a numerical justification for the massive stimulation jobs and the unexpectedly low hydrocarbon production obtained in several mudrock plays worldwide. Consequently, we demonstrate that massive fracturing treatments may not always be a successful development method in mudrock plays.
Combining Machine Learning and Physics for Robust Optimization of Completion Design and Well Location of Unconventional Wells
Authors: Rafiee Javad , Sarma Pallav , Zhao Yong , Plotno Sebastian , Calad Carlos , Betancourt Dayanara
Published: February 2022

Various types of predictive models have been applied over the years to make quantitative decisions for unconventional development plans. These models are either very simple (e.g., type-curves) which ignore the reservoir physics or are too complex (e.g., simulation models) to be able to run for an entire field efficiently. In this paper, we propose a model for design, prediction and optimization of unconventional wells efficiently using a combination of reservoir physics with machine learning methodologies. The proposed model is the amalgamation of the state-of-the-art in machine learning and reservoir physics into a seamless full field model. The physical model ensures that model predictions are always realistic and reliable while the machine learning algorithm allows us to utilize different types of data to make a prediction which cannot be directly integrated into the physical model. The model uses a probabilistic approach to estimate P10-P50-P90 production curves to account for uncertainty in predictions.

The data from more than 1800 unconventional wells in a real field is used to train and test our proposed model. The input features are completion design parameters like lateral length, proppant concentration, well spacing, etc., and the output in a full time series of expected oil production from the well. The results show that our modelʼs prediction leads to correlations of more than 0.75 for the test set which is indicative of its good predictive accuracy. The sensitivity analysis of the parameters of the model on the cumulative production shows that volume of injection fluid, length of the lateral and the proppant concentration are among the most important parameters.
A Parameter Optimization Workflow of Fractured Horizontal Well in Unconventional Reservoir: Case Study
Authors: Chen Zhiming , Chen Duo , Li Wanyang , He Yanxiang , Li Dexuan , Wang Jianan
Published: February 2022

The application of fractured horizontal wells has become an effective mean to improve the ultimate recovery of tight gas reservoirs. However, there still lacks of a complete and systematic approach to optimize the fracturing-treatment parameters of multi-stage fractured horizontal wells (MFHW), like fracturing-fluid volume, stage spacing, and proppant volume. In this paper, a transient flow model of horizontal wells in tight gas reservoirs is developed with considering complex fracture network generated by large-scale fracturing. Based on this model, an optimization workflow of fracturing-treatment parameter is presented by coupling rate transient analysis, performance forecast, and multivariate nonlinear fitting method. First, the reservoir/fracture parameters are evaluated using the rate transient analysis. Then, performance forecasts are performed by using the transient flow model. With multivariate nonlinear fitting, a relationship model between production volume and fracturing-treatment parameters is found, including average fracturing-fluid volume per stage (AFV), average stage spacing (ASS), and average proppant volume (APV). To demonstrate the reliability and practicality of the parameter optimization workflow, a field case is studied. The results show that in the field case the optimal AFV and ASS are respectively ranging from 900-1100 m3 and 60-120 m, while the optimal APV is ranging from 200-500 t. In this situation, the average cumulative gas production can reach 2.73×108 m3, increasing by an average percent of 28.26%. This study provides a new and feasible way for parameter optimization of fractured horizontal wells in tight reservoirs.
Foams to Control Slugging Issues in Pipeline - From Lab to Simulation
Authors: Chai Ching Hsia Ivy , Falope Bishop , Halim Nor Hadhirah , Rodzali M Azmeer
Published: February 2022

Hydrodynamic slugging or two-phase liquid-gas flow instability in pipeline has caused loss in flow capacity and intense vibration at the separator leading to integrity issues. This issue can be resolve using foams generated from surfactants which are introduced into the pipeline to entrap and slow down gas flow, thus enhance its mixing with liquids. To understand how the behaviour or foams in a pipeline impact or alleviate slugging performances, the foams behaviour in the pipeline was simulated using OLGA. First, two main parameters i.e. foams viscosity and interfacial tension in the presence of crude oil were obtained from precision lab experiments. Using a foam rheometer, foam viscosity with crude oil was measured under actual pipeline conditions. Surfactant and crude oil were injected into the rheometer until 500 psi was reached. Then, gas was injected into the loop at a given foam quality (fg). Foam quality, or the gas-liquid ratio was sensitized to 40- and 50% (e.g. fg=40 is 40% gas volume of the total fluids). Shear rates of 100 to 1000 s-1 were applied, and foam viscosities were recorded. For interfacial tension test, the pendant drop method was used. A drop of aged emulsion was drop into a continuous phase of nitrogen gas. The interfacial tension values were assumed as gas-water (without and with surfactant) and gas-oil, at 90:10 water:crude oil cut as per field condition. In the model, first the baseline of the hydrodynamic slugging behaviour was established and simulated using actual pipeline dimension, gas and liquid flow rates, and actual fluids properties, which showed obvious liquid fluctuations. The simulation established at which viscosity and interfacial tension values would have an impact in alleviating slugging by interpreting the output QLT - total liquid volume flow (bbl/d). Foam viscosity for both fg=40 and 50 showed shear thinning behaviour i.e. as shear rate increases, viscosity falls as accordance to the power law. In the model, viscosity as low as 2.5 cP (at 1000 s-1, fg=40) showed reduction in liquid fluctuations as read from the QLT arriving at the inlet of the pipeline, compared to baseline without foam viscosity input. Liquid fluctuations were reduced by 97% just from viscosity change due to presence of foam. Interfacial tension input at 0.024 and 0.021 mN/m for gas-brine and gas-oil, respectively in the presence of surfactant was able to reduce the number of QLT spikes by 24%. By combining the inputs of both parameters, a reduction of QLT or liquid fluctuations by a total of 97% was recorded. This study showed that foams were able to slow down gas velocity and reduced liquid fluctuations thus reducing slugging in one of the problematic pipelines in Malaysia. Accurate foam viscosity measurements generated from the lab remains a vital input to the model - so as to understand behaviour of foam and quantify its impact before actual field applications.
Characterizing Cohesive Zone Parameters to Model Crack Growth in Composite Materials
Authors: Al-Dakheel Hussain , Albinmousa Jafar , Temitope Idris
Published: February 2022

CFRP is gaining interest in several industries such as aerospace, sports, and oil field. When this material is assembled, the adhesive is considered a preference over screws and fasteners as screws holes can lead to matrix delamination. Prior applying an adhesive, surface pre-treatment is done to enhance bonding. Due to the complexity of the composite material namely in complex geometry, one can consider finite element analysis as an optimum method to model the material behavior. Failure of crack growth under cyclic loading is typically modeled using the CZM. However, finding the constitutive behavior parameters is considered challenging. In this work, the maximum stress, which is difficult to calculate experimentally, is estimated using the virtual closure technique (VCCT) as it is considered less complicated and costy than the conventional methods. The VCCT is a finite element method that is employed to simulate monotonic crack growth. From this model, the maximum stress is recorded and used as the maximum traction stress in the cohesive zone model (CZM) to simulate fatigue crack growth. The bilinear traction separation law was employed to simulate the cohesive process zone. To calibrate the model results, an experiment is conducted on two samples those were treated by two different methods. One sample has a sandblasting surface pre-treatment and the other is pre-treated by peelply. Each pre-treatment enhances different material toughness and hence validity of the results if supported. Both samples were tested under both static and cyclic loadings. The maximum energy release rate and the crack length were selected as comparison parameters between the models results and the experimental observations. Overall, it was noticed that the results are considered having reasonable fit.
A New Approach to Estimate Friction Factor for Horizontal Wells from Production Logging Data
Authors: Gok Ihsan Murat , Cevik Muharrem Hilmi , Cinar Murat
Published: February 2022

Conventional friction factor estimation is a challenging task for high flow rate horizontal wells since the roughness is an unknown parameter. In addition, pipe roughness may change with operational time due to the development of scale and corrosion in the horizontal section. This study aims to propose a methodology to estimate frictional pressure losses for horizontal wells by using production logging (PL) data. Prediction of pressure loss in horizontal well along perforations or open-hole is quite complicated due to complication in pressure drop. Different components of the pressure drop along the horizontal section are exist: Gravitation, acceleration, inflow/outflow, and finally friction. Estimation of frictional loss in horizontal wells needs to decompose of each term from total pressure drop in horizontal well. Data acquired during production logging provides an opportunity to determine friction factor since it indicates inflow/outflow zone with individual downhole flow rates of each phase. We clearly showed that friction pressure losses can be estimated for horizontal wells using PL data in certain cases. We verified this approach with synthetic PL data.
Developing Live RAM Model for Production Availability Evaluation
Authors: Mossa Walid
Published: February 2022

Objective

To build live-RAM (Reliability, Availability, and Maintainability) model to enable evaluating System Production Availability (PA) associated with variety of shutdown scenarios, with an objective to ensure Production optimization, Reliability improvement, and to support system de-bottlenecking. This Model is complemented by web-based updating tools to reflect changes in Production Profile, Maintenance plans, Reliability and Maintainability data, and equipment modifications.
New Type of Fluidic Oscillator Made Clean Out Operation Environment Friendly and Cost Effective – A Case Study that Converted Failure into a Success
Authors: Ahmed Barzan , Abdulrahman Khoshnaw Farhad , Raza Mustansar , Elmoneim Hossam , Dar Afnan Ahmed , Shakeel Ahmed
Published: February 2022

Untreated disposal of effluent water has the potential of scaling and plugging the in and near-wellbore regions. A case study and methodology adopted for the clean-out operation of water disposal well of Khurmala Field of Iraq is analyzed in the paper. Previous attempts of clean-out using high-pressure hydro- jetting tools along with acid treatment proved futile effort. As last resort, Fluidic Oscillator (SFO) was deployed for clean-out to regain access of TD and plugged fracture network before the eventual decision of work-over is made.

Combination of SFO having pulsing, cavitation, and helix jetting action in conjunction with train of fluids consisting of diesel, 28% HCl and gel were utilized. The operational sequence of clean-out was in stages of 10m to clean 79m interval, comprising of slotted liner and open hole, filled with detritus. Low bottom pressure required a dynamic approach for treatment-fluid nitrification based on the success of clean-out and access to liner and open hole. Annular velocities required nitrification once the slotted liner and open hole were open for in-take. Rate of penetration, sequence and volume of fluid-trains, nitrification, and batch cycling were designed in accord to changing downhole dynamics during clean-out.

A thorough investigation of detritus, designing of fluids, the accuracy of downhole hydraulics, and application of SFO proved to be an effective solution. It regained access to TD and connectivity between the wellbore and the injection zone. Injection increased from none to 15 bpm at 200 psi. The combination jetting effect of SFO (acoustic pulse (alike), cavitation, and helix) demonstrated to be more effective than rotating jetting tools. Moreover, the merits of operational efficiency supplanted conventional operations and environmental impacts were considerably low in terms of operating time, spent additives, and avoidance of work-over operation. The matching injection parameters post-operation with native parameters post-completion indicated that detritus is removed from wellbore and damage from the critical matrix is removed/bypassed.

Currently, SFO is the only technology that has pulse, cavitation, and helix jetting structures. It has an effective jetting for in and near wellbore region while the kinetic energy transferred via fluid makes the impact stronger in the deeper region. The internal mechanism of the tool allows it to handle high pumping rate and pressures while external finishing offers multi-port orientation for outflow that allows targeting the fill in desired directions. The tool does not require redressing, thus it proves to be an efficient, safe, and cost-effective alternative
Online Measurement and Analysis Technology of Oil & Gas Multiphase Flow by Magnetic Resonance
Authors: Deng Feng , Chen Shiwen , Chen Guanhong , Wang Mengying
Published: February 2022

The measurement and testing of oil, gas and water production accompany the entire oil industry from upstream to downstream. Oil and gas production, oil and gas testing, gathering and transportation, and economic transfer all need to be measured. However, the current production metering technology in oilfields is not perfect, and there are many problems such as poor accuracy, demanding phase separation, data delay, non-full range, additional pressure drop, huge equipment and high cost. In order to solve the above problems, since the 1990s, the development of multiphase flowmeters has been the goal of various oil companies and service companies in the world. A batch of non-separation or gas-liquid separation detection methods and commercial equipment based on electromagnetic waves, capacitance/conductance, ultrasonic waves, and gamma rays have emerged. The emergence of these new technologies has greatly improved production measurement accuracy and measurement frequency, and gradually replaced a batch of three-phase separators and measurement rooms. However, in the face of increasing production stimulation wells (wells with EOR measures), unconventional wells (high salinity, with condensate, high gas, high water cut, heavy oil wells) development, as well as special projects such as oil and gas testing. The demand for multiphase flowmeters is becoming more and more urgent. The application scenarios of commercial multiphase flowmeters are limited, non-three-phase full range, short maintenance period, high cost, and other problems have become prominent.

Magnetic resonance (MR) technology is considered to be the most promising multiphase flow measurement technology, but at present it also needs to solve technical problems such as low measurement frequency, static measurement of phase holdup, poor environmental adaptability of the instrument, and high cost. However, there is no precedent for the application of MR technology to the phase holdup detection of fast flowing fluids, which is mainly limited by the signal loss under fast flow, low signal-to-noise ratio, and low magnetic susceptibility.

In the previous work, we proposed a multiphase flow measurement method of "dynamic flow velocity + static phase holdup". On this basis, this paper further innovates and proposes a dynamic phase holdup detection method, which in a real sense realizes the online magnetic resonance measurement and analysis of multiphase flow. At the same time, a set of industrialized MR multi-phase flowmeter was developed, and the error of the liquid phase in the field test was less than 5%, and the error of the gas phase was less than 10%.
A Pilot Demonstration of Flaring Gas Recovery During Shale Gas Well Completion in China
Authors: Xue Ming , Li Xingchun , Cui Xiangyu , Wang Qi , Liu Shuangxing , Zheng Jiale , Wang Yilin
Published: February 2022

Objectives/Scope

As one of the largest emitters in the world, the oil and gas industry needs more efforts on greenhouse gas reduction. Methane, as a potent greenhouse gas, could largely determine whether natural gas could serve as a bridging energy towards a sustainable future. In the past decade, the oil and gas companies in China has significantly enhanced casing gas recovery and reduced large volume of flaring (>20k m3/day). However, the remaining low- to mid- volume flaring gas were left for further recovery.

Methods, Procedures, Process

Shale gas production in China has met a surge in the number of drilling wells. Those new wells were characterized by a relatively low gas production rate (<1 mill m3/day), in comparison with the shale gas well in the US. As a result, flaring gas during well completion needs to be recycled or used so as to enhance the gas recovery rate. In this study, a pilot demonstration project of flaring gas recovery was carried out to reduce greenhouse gas emission in Weiyuan shale gas region in Sichuan province, China. The technical route of dehydration and natural gas compression was adopted. The recycled natural gas was transformed into compressed natural gas (CNG) and transported to the nearest CNG station for further use.

Results, Observations, Conclusions

The inlet gas pressure were between 2.85 to 5.82 MPa and the outlet pressure were kept stable around 20 MPa to meet the standard of CNG. The minimum dew point temperature was -65.5 °C and the outlet temperature rise remained below 23 °C. The manufactured device also showed a sound flexibility with recover rate between 523.22 to 1224.38 m3/h, which was the 28% to 157% of the designed capacity. An overall of 21k of natural gas was recoverd.

Novel/Additive Information

For a single well completion event, a total of 50k of natural gas could be recovered by this device. The device applied in the pilot demonstration has well matched with the local transportation, gas composition, and surface engineering of the well completion and has the potential of popularization and application in the shale gas region in Sichuan. In that case, it could reach a future economic return over 0.6 billion RMB.
A Multidisciplinary Approach to Production Optimization through Hydraulic Fracturing Stimulation and Geomechanical Modelling in Clair Field
Authors: Dumitrache Liviu , Roy Alistair , Bird Anastasia , Goktas Baris , Sorgi Claudia , Stanley Reginald , De Gennaro Vincenzo , Eswein Edmund , Abbott Jonathan
Published: February 2022

The integration of data and discipline specific knowledge is a common challenge when attempting to optimize or accelerate an asset's recovery through hydraulic fracture stimulations. Any potential omission of data or understanding will increase uncertainty and a project's chance of failure. Therefore, when looking to optimize the production of a given asset, it is key to take a holistic approach that breaks down any technical and organisational barriers.

This project couples the output of the different subsurface and stimulation disciplines to reduce the uncertainty associated with the production forecast of planned stimulation designs. The following paper presents the integrated approach for the Graben sector of UK's North Sea Clair oil field, largest oil field currently in Europe.

Geophysicists, petrophysicists, and geologists generate a static model which is calibrated and validated by reservoir engineers through dynamic reservoir simulation. This model is used to identify the optimum exploitation scenario for a hydrocarbon reservoir and is assessed by the geomechanics engineer to deduce the subsurface stresses and strains to create a 3D mechanical earth model. The multidisciplinary validated representation is handed over to the stimulation engineer to implement various treatments, either performed or to be performed. Once these treatments are designed, the reservoir engineer produces a production forecast which is then fed back to all team members involved in the process, enabling an optimization loop. Considering that this is a multi-well (producers and injector) study, any inference is reflected by the analysis and the optimum hydraulic fracture design is chosen for implementation by an offshore stimulation vessel.

Traditionally, for forecasting purposes, hydraulic fractures can be implemented using conventional reservoir simulation; however, these are very much approximated models of what the stimulation engineers are designing and implementing. Often, the reservoir, production, stimulation engineers can come up with individual forecasts that are obtained independently and omit basic information. A typical example is the way stresses might change due to stimulation and production and the possibility to account for them in an integrated way. The proposed workflow eliminates these shortcomings, and the asset team delivers a single forecast of the exact fracture design considering a fully consistent model of the subsurface, which is to be implemented by the stimulation vessel for the different wells.
Well Integrity Solutions Using Intelligent Field Remote Surveillance and Monitoring Systems
Authors: Al-Hajji Haider , Onikoyi Abiola
Published: February 2022

Well Integrity Monitoring provides means to protect the people, environment, reputation and assets of oil and gas operations globally. While being a vital tool for preventing safety and economic mishaps in oil and gas wells, it is also one of the primary responsibilities of the Production Engineer. Three examples of technological advancements in the area of real-time data monitoring and intelligent-field visualization systems, which have largely enhanced the capabilities of the Production Engineer to monitor Well Integrity parameters across large fields are presented.

The real-time data monitoring and intelligent-field visualization system functions based on a feedback loop system, which continuously monitors well integrity parameters such as pressure, temperature, voltage and current. The output from the probes installed in the well are passed to a Central Processing Unit where the electrical signal is processed, converted to well integrity parameters and compared with set points. Deviation are recorded and anomalies are flagged off for prompt intervention.

Continuous real-time monitoring of Annuli Pressure, Well Head Pressure and Voltage/Current led to timely identification of Well Head Casing Leak, Failed Well Head Valve and corroded casing respectively in the three cases studied. The most significant new finding is that anomalies in other cases typically take up to one year to identify due to less frequent integrity survey practice adopted in fields where the intelligent-field technology is non-existent. This is important because timely intervention made possible by real-time monitoring systems safeguards corporation assets, reputation and the environment.

The implemented Intelligent Field Remote Surveillance and Monitoring System has shown its significance in optimizing well integrity solutions in large fields, protecting people, enabling prompt intervention and saving the environment.

To achieve this target, collaboration within several departments and organizations is required within an oil company. As such, the concept can only be successful if it is part of the corporate vision and is driven at a high level in any company.
Improvement on Dry-Out Procedures Using Sacrificial Thermocouples
Authors: Al Hajeri Nuha , Medina Antonio , Al Ameri Mohamed , Godoy Zambrano Cesar , Vera Douglas Edward , Majumdar Pradip
Published: February 2022

Although refractories materials are resistant to high temperatures, the initial mechanical properties are drastically influenced by the way of removing the water and further development of ceramic bonding reactions during the firing process of dry-out. Lifetime of monolithic refractories can be reduced when mechanically induced cracks are developed and laminations or spalling of outer layers is promoted.

Refractory dry-out process is normally accomplished by utilizing installed combustion means and permanent temperature monitoring instrumentation, strategically placed in specific locations to cater normal operation and protection of the equipment. Controlled heat up is followed by adjusting the combustion parameters to achieve the desired rates to safely complete the drying process for refractories materials.

However, these permanent thermocouples cannot anticipate local temperature profiles as part of the normal heat distribution inside the combustion chamber. For that reason, sacrificial thermocouple is the most suitable local temperature measurement device to cover the specific interested spotted location inside the chamber during firing operations avoiding excursion outside dry-out plan.

This paper will display ADNOC Sour Gas experience on utilizing sacrificial thermocouples in order to monitor temperature for operational drying out activities after refractory repairs. This will provide other companies which has no experience with installing sacrificial thermocouples for the same purpose, the confidence to implement and to install it for refractory dry-out and thus, preventing any premature failure on refractory materials.

The importance of dry-out procedure and its effect on the material properties will be further explained along with the methodology of installing sacrificial thermocouple, key parameters to follow during the dry-out plan and temperature profiles using sacrificial thermocouples Vs installed instrumentation will be presented on the technical discussion.
Frequency Dependent Rock Mechanical Properties for Geomechanical Applications
Authors: Syed Shujath Ali , Jin Guodong , Ma Shouxiang Mark
Published: February 2022

Geomechanical applications including wellbore stability evaluation, sanding assessment, and hydraulic fracturing design require rock mechanical properties (e.g. Young's modulus) as inputs. Significant discrepancy exists for the same property measured with various techniques due to different loading frequency and deformation amplitude applied, potentially resulting in added uncertainties in the applications. This paper presents the development of a prediction model enabling to determine mechanical properties consistently at any applied frequency. To build the prediction model, we first conducted measurements of Young's modulus and Poisson's ratio on sandstone samples over a wide frequency range from laboratory standard triaxial tests (~10−5 Hz), downhole logging (~20 KHz), to laboratory ultrasonic measurement (~1 MHz). These data provide a better understanding of frequency-dependent rock mechanical properties. Rock samples having different porosities and permeabilities are selected for investigating their effects on frequency-dependent acoustic wave velocities. Static measurements of Young's modulus and Poisson's ratio are also conducted to complete the measurements spectrum from static to dynamic frequencies. From the experimental data, the prediction model is developed to correlate rock elastic properties with measurement frequencies, which is further used to determine mechanical properties at any desired frequency for various geomechanically applications.

As expected, the measured Young's modulus increases as the applied frequency increases, which is mainly due to the stiffening mechanism of the rock. The dispersion analysis of the results indicated a higher degree of stiffening for the higher porosity samples. The prediction model of Young's modulus vs the frequency was built and used to calculate the Young's modulus at the logging frequency from the available ultrasonic measurements. The predicted Young's modulus is compared well with the actual values obtained from acoustic logging data. On the opposite, Young's modulus at the ultrasonic frequency was calculated from the logging data using the prediction model and compared well with the measured Young's modulus at the ultrasonic frequency. Good agreement between the predicted and measured Young's moduli demonstrates the effectiveness of the prediction model, and its capability to derive the desired Young's modulus, such as the static, from the dynamic values measured from downhole logging data. The prediction model was developed from a physics based approach to derive the desired rock mechanical properties from their dynamic values measured at the logging or any other frequency, which potentially makes it unnecessary to develop traditional static vs dynamic correlations for various geomechanically applications.