bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Fourble Land Rig and its Application in Ultra Deep Well Drilling
Authors: Chen Peng , Wang Junjie , Ding Mingming , Yang Xiuying , Zhou Tuo , Zhong Zhao
Published: March 2021

A traditional land rig uses tribble in drilling operation. A novel fourble land rig using four joints as a unit has been researched and developed in order to promote operational efficiency in ultra deep well drilling. Design, overall plan and crucial techniques as well as the field application result of the fourble drilling rig are presented in this paper.

The fourble land drilling rig was studied based on the conventional tribble rig which utilizes three joints as a unit or a tribble. However, the novel rig adopts four joints as a unit or a fourble. Therefore, the improvement of the drilling operational efficiency could be realized by extending the length of the stand, reducing trip time and frequency, and increasing the high speed operational time of the travelling block. The extra high derrick design, fourble handling and drum roping techniques of the 9000m fourble land rig were researched.

The fourble land drilling rig with nominal drilling depth of 9,000m was designed and manufactured. The heights of the derrick and racking platform of the fouble rig were increased. The rig is able to run in hole and pull out of hole the fourble united by four joints. The high speed tripping distance gets longer, and the setback capacity gets increased. Ultra deep well drilling in the piedmont zone of Tarim basin in Xinjiang, China showed the reliable integral performance and substantial enhancement of drilling speed. The average drilling time using the fourble rig could be 15%-30% decreased as compared to that of the traditional tribble rig. The cycle of drilling would be cut down and cost of drilling would be reduced for ultra deep wells by means of the fourble rig.

Oil and gas reservoirs were deep buried in depths of 7,000m-9,000m in the submountain area of Tarim basin where the ultra deep wells drilling are increasingly growing. The novel fourble land rig was developed in high demand of efficient drilling of ultra deep wells. It filled the gap of China's drilling rig series.
The Road to Zero Routine Gas Flaring: A Case Study from Saudi Arabia
Authors: Alsuwailem Majed
Published: March 2021

Gas is envisaged as the fuel of choice in the power sector and is ideal for helping to transition toward clean, sustainable, and affordable energy access. As vital as gas is for electricity generation, the petrochemical industry, the transportation sector, and heating, many oil operators either flare or vent associated gas, a by-product of oil extraction, at the wellhead or gathering stations. Gas flaring releases greenhouse gases (GHGs) into the atmosphere. It occurs for various reasons, including infrastructure and financial constraints to capture the gas, inadequate regulatory frameworks, or binding contractual rights.

The World Bank estimated the amount of flared natural gas in the oil and gas industry reached 5.1 trillion cubic feet (tcf) in 2018 (World Bank 2018). The amount of energy lost due to flaring or venting this gas is equivalent to more than 770 billion kilowatt-hours (kWh). It releases more than 310 million tonnes of carbon equivalent. Many countries and oil operators have managed to mitigate gas flaring and venting across their oil and gas value chains due to these troubling statistics.

One such example is the Kingdom of Saudi Arabia. Before 1975, the Saudi oil and gas industry flared or vented over 4 billion standard cubic feet (SCF) of associated gas, a by-product of oil extraction. The flaring intensity would have increased had it not been for the construction of Saudi Arabia’s Master Gas System (MGS).

The Kingdom’s gas flaring mitigation process is a successful case study of how governments and oil operators can collaborate to eliminate gas flaring by developing a domestic market for gas and enhancing the value of natural gas resources. It also demonstrates the successful transition that the kingdom had in the past five decades to achieve zero flaring through technology deployment and advancing the "reduce" component of the circular carbon economy.

This paper discusses Saudi Arabia’s progress in gas flaring, the measures the government has taken thus far, and how operators have adapted to them. It also identifies many lessons learned and technological solutions that could be scaled up on a national or a corporate level to reduce gas flaring towards achieving zero routine flaring targets, especially in cases where the state owns hydrocarbon assets and leases them to private operators.
Acceleration of New Technology Qualification and Deployment for Sand Level Measurement in Production Vessels
Authors: Myo Thant Maung Maung , Che Daud M. Faizal , Shaffee Siti Nur , Chua Kien Kiet , Nissinen Antti , Kartikainen Jouni , Laakkonen Pasi , Li Alan Ong
Published: March 2021

Measurement of sand build-up in the production separators has been a challenge for field personnel due to the limitations of current technologies. Nucleonic-type level profiler has been previously implemented in a few offshore locations but limited due to special handling and permit/license requirements of radioactive material involved. Therefore, this paper aims to present the acceleration of new non-nucleonic tomographic technology testing and qualification to measure accumulating sand in separators as well as multi-disciplinary approvals for fast-track field application.

The general idea in tomography is to expose the target of interest to electrical signals and measure the response of the target. With the aid of mathematical models, it is possible to infer the distribution of different materials within the target from the responses. Results of tomographic measurements are displayed on a computer as a vertical profile. The tested tomographic solution was based on a tomographic technology called Electrical Tomography. The key idea in Electrical Tomographic image construction is to find a permittivity and conductivity distribution for which the observations predicted by the model are in good agreement with actual ET measurement data and hence profiling is to be created.

The test was performed at the laboratory with a full tomographic profiler setup including a test probe sensor for profiling, electronics, and a computer unit. In addition to the tomographic instrumentation, a transparent plastic vessel was used for visual observations of the accumulated sand layers. Visual observations were made simultaneously with tomographic imaging. In the test setup, we had sand, water, emulsion, and oil. The samples were placed into a transparent vessel. It was visually observed that the probe sensor was able to distinguish "wet sand-water" interface and "water-oil interface" in all the tested conditions. At the end of the test, the sand layer was flattened and packed more tightly and the change in the layer thickness was seen in the tomographic image. We concluded that the resolution of the detection of the sand layer was in the range of 1-2 cm. The technology is novel as it is a non-nucleonic profiler and a field-safe technology to be used. The profiler is intrinsically safe and certified to the most demanding IECEx class to be used in Zone 0 hazardous atmospheres.

Detailed engineering of the technology to be installed at one of the production separators has proceeded. Finite Element Analysis has shown that the system can withstand turbulent conditions within the multi-phase production separator.
First-Time Insights into Hydraulic Fracturing of Unconsolidated Sands from Novel Laboratory Experiments with in-situ CT-Scanning
Authors: de Borst Karin , Tan Chee Phuat , Mat Piah M. Faizzudin , Groenenboom Jeroen
Published: March 2021

Waterflooding in unconsolidated sands has been observed to frequently result in injectivity decline of injectors when operated under ‘fractured’ conditions, resulting in reduction of waterflooding value creation and potential premature injector failure. Optimization of injector design and operation is currently limited by an insufficient understanding of the mechanics of ‘fracture’ and its associated mechanisms in unconsolidated sands, and the lack of adequate quantitative tools to predict injection performance.

Utilizing in-situ CT scanning during large-scale laboratory injection experiments delivered novel insights into generation, closure and re-opening of ‘fractures’ in sand packs built from synthetic sands and highly unconsolidated downhole core material. Cavity formation was identified as main ‘fracturing’ mechanism. The cavities opened at injection pressures exceeding the confining stress and subsequently enlarged against a very low cohesive strength for the downhole core sands. This suggests material fluidization rather than shear failure as the immediate cavity initiation mechanism. Injectivity was found to be controlled by the interplay of fines transportation away from the injection region, resulting in injectivity increase, and the permanent compaction of the sand around the cavity, resulting in injectivity decrease.

These first-time insights challenge the current understanding of matrix vs ‘fractured’ injection in unconsolidated sand reservoirs and highlight the role of sand fluidization and cavity formation. Furthermore, the injectivity behaviour is dependent on the combined effects of the sand material, the presence of fines, and the injection flow regime. The knowledge of the sand destabilization and mobilization processes enable design and operation optimizationof water injectors with implications on sand control strategies and remediation measures.
Digital Transformation of Borehole Sonic Services in the Oil and Gas Industry
Authors: Donald J. Adam , Wielemaker Erik , Velez Edgar , Liang Lin , Lei Ting , Blyth Matthew , Prioul Romain
Published: March 2021

Sonic data are commonly acquired in exploration, appraisal, and development wells using wireline, logging-while-drilling, or through-the-bit conveyance for applications within petrophysics, geophysics, geomechanics, and geology disciplines. The measurement data require processing to obtain elastic wave slownesses (inverse of velocity) and associated attributes before the results can be used in petrotechnical workflows. The objective of the digital transformation is to streamline and automate the processing workflow to reduce user intervention and turnaround time while increasing the accuracy of results and possibly extracting more answers by fully utilizing all waveform attributes, which consequently benefits downstream applications.

There are four workflows that are the foundation of the transformation. They support the overall goals of reducing user interactions and providing robust results in a timely manner for continuous slowness logs. First, data-driven inversions done during acquisition with automatic quality control and interpretation flags immediately provide assurance about the data quality and identify formation intervals that require further evaluation. Second, automatic dipole-flexural shear extraction is done using physics-based machine learning (ML) where purely data-driven models are inadequate due to borehole or geological conditions. The physics-based ML utilizes cloud-based computing that is needed for large volume synthetic data generation and neural network training. Third, a multiresolution analysis of the monopole waves for the compressional slowness uses automatic peak detection on multiple receiver levels removing any subjective manual labeling after the semblance processing. Finally, the multimode (flexural and Stoneley) inversion determines anisotropic constants and accounts for mud-speed variations in the borehole, including detailed uncertainties.

The new methods address underlying concerns most users and waveform processing experts already observe in their sonic deliverables. Enabling wellsite algorithms to be more automatic and data driven improves the robustness of the field deliverables and provides insight into the quality of the data. For the shortcomings with regards to borehole or geological conditions such as laminations, sharp lithological transitions, or the presence of anisotropy, the physics-based ML is shown to honor the physics of the dipole flexural mode, while the multiresolution for the monopole provides physics-based reasoning for discrepancies between the geological layering and receiver aperture. By incorporating the range of results derived from the inversions with advanced interpretations such as transversely isotropic constants, these uncertainties can be further used in stochastic models in downstream workflows. All these methods are fully automated and can be done in a short timeframe to be used without doubt in operations.
Integrated Reservoir Geomechanics Approach for Reservoir Management
Authors: Hon Vai Yee , Mat Piah M Faizzudin , M Fauzi Noor 'Aliaa , Schutjens Peter , Agarwal Binayak , Harris Rob
Published: March 2021

An integrated 3D dynamic reservoir geomechanics model can provide a diverse 3D view of depletion-injection-induced field stress changes and the resulting deformation of both reservoir and overburden formations at various field locations. It enables the assessment of reservoir compaction, platform site subsidence, fault reactivation and caprock integrity associated with multiple production and injection reservoirs of the field. We demonstrated this integrated approach for a study field located in the South China Sea, Malaysia, which is planned for water injection for pressure support and EOR scheme thereafter. Reservoir fluid containment during water injection is an important concern because of the intensive geologic faulting and fracturing in the collapsed anticlinal structure, with some faults extending from the reservoirs to shallow depths at or close to the seafloor.

Over 30 simulations were done, and most input parameters were systematically varied to gain insight in their effect on result that was of most interest to us: The tendency of fault slip as a function of our operation-induced variations in pore pressure in the reservoir rocks bounding the fault, both during depletion and injection.

The results showed that depletion actually reduces the risk of fault slip and of the overburden, while injection-induced increase in pore fluid pressure will lead to a significant increase in the risk of fault slip. Overall, while depletion appears to stabilize the fault and injection appears to destabilize the fault, no fault slip is predicted to occur, not even after a 900psi increase in pore pressure above the pore pressure levels at maximum depletion. We present the model results to demonstrate why depletion and injection have such different effects on fault slip tendency. The interpretation of these geomechanical model results have potential applications beyond the study field, especially for fields with a similar geology and development plan. This is a novel application of 3D dynamic reservoir geomechanics model that cannot be obtained from 1D analytical models alone.
Feasibility Study of Offshore Hybrid Technology for High CO2 Gas Field Monetization
Authors: Ahmad Zuhdi M. Faizan , Rahman F. Hadana , Shahjavan Hamid , Mas’od M. Azlan , Salihuddin R. Suhaib , Zulkepli N. Ashikin , Alias Azila , Jalani M. Yazid , Yiin Tan Kin
Published: March 2021

The CO2 capture technology is well understood in the oil and gas industry. However, to unlock the Hydrocarbon from an ultra-high CO2 offshore field (more than 70% mol), special attention is needed to capture CO2 for a field development to be economically attractive. Therefore, the current technology inventory needs to be studied to achieve project goals and at the same time achieving Carbon Capture and Storage (CCS) requirements. A hybrid of multiple carbon capture technology will help to improve the hydrocarbon (HC) loss, reduce both operational and capital cost and minimize overall auto consumption. The hybrid of cryogenic distillation (CryoD), membrane and supersonic gas separation (SGS) was studied to explore its feasibility.

To enable ease of CO2 transport and handling, CO2 is preferred to be in liquid form. In order to achieve this, CryoD technology is the preferred solution for bulk removal. CryoD is also able to cater to the feed gas fluctuation and becomes a robust candidate for high variance feedstock. However, being dependant on sub zero working temperatures, the system will require larger equipment footprint and tonnage.

The focus of the study is to evaluate the sensitivity impact of an operating condition on the Hybrid configuration of CryoD + membrane (CM) and CryoD + SGS (CS. Areas of focus will be equipment tonnage and footprint, power consumption and eventually cost (CAPEX & OPEX).

The monetization of ultra-high CO2 gas field is then made feasible by using hybrid Acid Gas Removal Unit (AGRU) to meet sales gas specification. The CryoD + membrane technology is the preferred solution for offshore system.
Optimising Well Times Through Drilling Connection Practices
Authors: Mohd Mazlan Faisal , Ahmad Redzuan Ahmad Zhafran , Amiruddin Mohd Idzwan , Ramli Ahmad Faizal , Slagel Pete , Mondali Mondali
Published: March 2021

From an operator's perspective, many operational instructions are written implicitly that are not sufficiently detailed to optimize drilling efficiency. Upon a review of several partner operators’ drilling performance, it was noticed that there was a significant focus on the following aspects of technical limit drilling: ROP, tripping speeds, offline activities and connection times. One operator specifically reviewed Gulf-of-Thailand best practices and implemented them in Malaysia.

One of the significant areas of improvement includes drilling connections. In the previous version, PETRONAS Malaysia Drilling Operations follows a conservative ERD connection method requiring to ream a single/stand, take a good survey a minimum 10m off bottom prior to making a connection and applied to all wells regardless of inclination or complexity. This was in response to risk of stuck pipe incidents happening during these critical static periods.

A comparison of the connection times after their change in practice compared to PCSB practices given the same tools and well complexity indicated massive potential time savings with no additional costs. A change in the drilling connection practices could easily save almost half of this particular "flat time" with no significant risk, amounting to a possible saving of almost 26 hours in a well of around 3000m MDDF. This also led to a better understanding of the impacts of certain "rule-of-thumb" practices that needed to be questioned from time to time.

This comparison coupled with many existing literatures available allowed a data-driven approach to improving well times. Some of this information is easily glossed over considering the only time-based data most wells refer to would be the Daily Drilling Report. This paper also emphasizes the importance of data collection and usage of historical databases to search for more opportunities in terms of safety, cost and time.
Subsurface Back Allocation: Calculating Production and Injection Allocation by Layer in a Multilayered Waterflood Using a Combination of Machine Learning and Reservoir Physics
Authors: Rafiee Javad , Calad Serrano Carlos Mario , Sarma Pallav , Plotno Sebatian , Gutierrez Fernando
Published: March 2021

Allocation of injection and production by layer is required for several production and reservoir engineering workflows including reserves estimation, water injection conformance, identification of workover and infill drilling candidates, etc. In cases of commingled production, allocation to layers is unknown; running production logging tools is expensive and not always possible.

The current industry practice utilizes simplified approaches such as K*H based allocation which provides a static and inaccurate approximation of the allocation factors; this manual approach requires trial and error and can take several weeks in complex fields.

This paper presents a novel technique to solve this problem using a combination of reservoir physics and machine learning. The methodology is made up of four stages:

Data Entry: includes production at well level (commingled), injection at layer level and injection patterns or a connectivity map (optional) Gross Match: in order to match gross production for each well, the tool solves for time-varying layer-level injection allocation factors using a total material balance equation across all wells. Phase Match: having the allocation factors from the previous step, the tool automatically tunes various petrophysical parameters (i.e. porosity, relative permeability, etc.) in the physics model for each injector-producer pair across all the connected layers to match the oil and water production in each producer. An ensemble of several models can be run simultaneously to account for the probabilistic nature of the problem. Output: The steps 2 and 3 can be performed at pattern level for all connected patterns or for the whole field.

The application of the technology in a complex field with 80+ layers in Southern Argentina is demonstrated as a case study of the benefits of the adoption of the technology.
Prediction Of Shut-in Bottom-hole Pressure From Wellhead Pressure Considering Transient Behaviour Of Hydrostatic Pressure Loss During Shut-in
Authors: Maki Satoshi
Published: March 2021

Shut-in bottom-hole pressure (SIBHP) is key information to monitor reservoir depletion and thus to evaluate gas in place for a gas field. Permanent downhole gauges are widely used to continuously measure bottom-hole pressure especially for subsea wells. However, when gauges fail, a large cost of workover for gauge replacement is a major problem. In case of the gauge failure, SIBHP hence needs to be estimated from measured surface data such as wellhead pressure (WHP) and wellhead temperature (WHT). The use of WHT for subsea wells however leads to a large error of the SIBHP calculation because sea current significantly affects WHT readings during shut-in. This study aims to develop a correlation methodology to predict SIBHP from surface data without using WHT.

We have developed a linear correlation of hydrostatic pressure loss during shut-in with superposition time to predict SIBHP from WHP. Using superposition time of well production status with zero or one indicator effectively accounts for transient behaviour of hydrostatic pressure loss caused by cooling of wellbore fluid and pressure build-up. The transient behaviour differs by individual wells. Hence, the coefficients of the correlation were calibrated well by well to reproduce observed SIBHP.

The correlations were applied to the Ichthys gas-condensate field located in the Browse Basin, North West Shelf of Australia. SIBHP trends are reasonably reproduced by the correlations after calibration. A blind test was performed using additional 18 months production data to investigate the predictability of the proposed correlation. As a result, high accuracy of the prediction is confirmed with an average absolute error of approximately 0.4% for the test period. The SIBHP of wells in which downhole gauges have failed is predicted by the calibrated correlations, and the predicted SIBHP is utilised for the reservoir management of the Ichthys field.

We present the novel methodology to predict SIBHP from observed surface data without WHT for subsea gas-condensate wells considering the transient behaviour of hydrostatic pressure loss. The proposed correlation provides accurate prediction of SIBHP in case of the gauge failure.
Verification and Application of CTV Technology for Deep Sea Crude Oil Offloading in Brazil Project
Authors: Wang Zhixiang , Zeng Xianglin , Li Bo , Xiao Yue
Published: March 2021

In view of the problem of high risk and high cost of deep-sea crude oil export technology, this paper starts with the problem that DPST (Dynamic Positioning Shuttle Tanker) in Brazil's one deep sea project compulsorily be used in offloading operation. From coordinating and participating in the comparison and selection of offloading schemes from CNOOC and individual partners, to the raising of technical proposal CTV (Cargo Transfer Vessel) and subsequent carrying out of ship design, construction, sea trial and until actual application, this paper fully discusses and verifies CTV's correctness and adaptability. As the world's first unique technological solution for the offloading issue. its excellent security and low cost advantages will assure CTV a greater role in the field of deep sea oil offloading and other marine areas.
A Compelling Case: Time to Change Minimum Curvature Survey Method for Well Engineering Calculations
Authors: Samuel Robello
Published: March 2021

Several calculation methods have been proposed by the researchers in the past with varying degree of precision. These result in different wellbore position estimation. The survey calculations and positions are used in engineering calculations such as torque and drag, drill ahead prediction, displacement of the string, SAG correction etc. Since the survey calculations are the underpinning starting point for the engineering formulations, considerable errors are introduced in the engineering calculations. Most widely used method in the industry is minimum curvature which assumes a circular arc in an inclined plane and this method is better than some of the previously introduced methods like balanced tangential method, average angle method etc. It has also been seen that, the radius of curvature method is more suitable for a rotary mode of drilling, whereas the minimum curvature method aligns when slide drilling. However, using the minimum curvature method, introduces discontinuity at the survey course intervals. This type of constant curvature model due to discontinuity may result in the omission of some contact forces which will result in the under prediction of the hookload or the stresses in the drillstring components or casing or drillpipe wear calculations. This further results in the discontinuity in the engineering calculations also and will be more pronounced when the wellbore twists and turns. To alleviate this problem, wellbore smoothening is done by using advanced survey methods such as spline, natural arc method, curvature bridging etc. A reliable inclination and directional continuous surveys also enable smooth and continuous wellpath making the problem with the minimum curvature method to vanish.

This paper presents the research findings not only on the relationship between the minimum curvature method and engineering calculations but also the inherent problem in the commonly used survey calculation methods. It has been shown that both wellbore curvature as well as the borehole torsion are necessary to relate to the mechanical parameters that are used in the engineering calculations such as bending moment, side force and string position.
A New Method of Reproducing Rock Samples with Rough Surfaces for Testing Conductivity: A Case Study on Shale Propped Fractures
Authors: Chen Chi , Wang Shouxin , Lu Cong , Wang Kun , Lai Jie , Liu Yuxuan
Published: March 2021

Hydraulic fracturing technology provides a guarantee for effective production increase and economic exploitation of shale gas wells reservoirs. Propped fractures formed in the formation after fracturing are the key channels for shale gas production. Accurate evaluation of local propped fracture conductivity is of great significance to the effective development of shale gas. Due to the complex lithology and well-developed bedding of shale, the fracture surface morphology after fracturing is rougher than that of sandstone. This roughness will affect the placement of the proppant in the fracture and thus affect the conductivity. At present, fracture conductivity tests in laboratories are generally based on the standard/modified API/ISO method, ignoring the influence of fracture surface roughness. The inability to obtain the rock samples with the same rough morphology to carry out conductivity testing has always been a predicament in the experimental study on propped fracture conductivity. Herein, we propose a new method to reproduce the original fracture surface, and conductivity test samples with uniform surface morphology, consistent mechanical properties were produced. Then, we have carried out experimental research on shale-propped fracture conductivity. The results show that the fracture surfaces produced by the new method are basically the same as the original fracture surfaces, which fully meet the requirements of the conductivity test. The propped fracture conductivity is affected by proppant properties and fracture surface, especially at low proppant concentration. And increasing proppant concentration will help increase the predictability of conductivity. Due to the influence of the roughness of the fracture surface, there may be an optimal proppant concentration under a certain closure pressure.
Research Method of Phase Behavior in Gas-Crude System and the Application in L Block with HP/HT
Authors: Jiang Tongwen , Zhou Daiyu , Wu Yiming , Chang Lunjie , Lian Liming , Wu Zangyuan , Zhou Wei , Fan Kun , Tang Yongliang , Yu Hongwei , Bian Wanjiang , Shao Guangqiang , Fan Jiawei , Wu Lin , Huang Lan , Kuang Xiyu , Fan Jin , Li Yang
Published: March 2021

This paper provide improved phase behavior models, trying to mitigate the problem that phase behavior of gas-crude system is difficult to describe in L block with low permeability and high water cut in China. This situation leads to a series of problems in CO2 flooding process and lower recovery up to expectations. The models is evaluated to possess both high calculation speed and accuracy compared with existing others.

Characteristics of CO2-crude systems had been considered into repulsion-attraction type EOS (equation of state) based on the analysis of repulsion parameter and attraction parameter in EOS, and the improved EOS had been applied in developing calculation method of MMP (minimum miscible pressure). No ideality of CO2-crude systems had been considered into mixing rules of CO2-crude systems based on analysis of mixing rules of repulsion-attraction type EOS. Promotion had also been put into the obtain methods of parameters in phase behavior, including density, viscosity, MMP, critical parameters of plus components etc. All these methods are applied in L Block.

The phase behavior models of CO2-crudes system promoted in this paper mainly include EOS, mixing rule and viscosity model and have been applied in CO2 flooding process in T Reservoir. The relative error of density calculation is reduced from 7% ∼ 20% to less than 1%and the modified EOS is applied to predict the MMP of the CO2-crude systems from 8 different blocks in T reservoir. The modified EOS also works well for the relative error of MMP prediction is reduced from 20% ∼ 70% to less than 5%. Compared with the existing mixing rules, the modified mixing rule is with higher calculation speed and accuracy. The relative error of components mole fraction calculation is reduced from 30% ∼ 80% to less than 10%. Compared with the existing viscosity models, there are large improvements of the modified viscosity model in accuracy. The relative error of viscosity simulation is reduced from more than 50% to about 5%. According to the simulation results, C2∼C15 are the key hydrocarbons with positive effect on the miscibility of CO2-crude systems, while C16+ are the key hydrocarbons with negative effect. The recovery of the pilot has increased by 23% by these methods.

The improved phase behavior models provided in this paper possess as good performance as existing models in calculation speed, and accustom a big step forward in simulation accuracy. The modified components of the models also partially complete physical meaning in describing phase behavior of CO2-crude system. All the models mentioned above are finally applied in L block with HP/HT and high water cut and obtained an increase in recovery by 19.2%.
Research on Plugging Mechanism and Optimisation of Plug Removal Measure of Polymer Flooding Response Well in Bohai Oilfield
Authors: Chen Huaxing , Wang Yufei , Pang Ming , Fang Tao , Zhao Shunchao , Wang Zhiyuan , Zhou Yugang
Published: March 2021

Since the field test of polymer flooding technology was carried out in the Bohai Oilfield in 2003, problems such as plugging of polymer-response wells have become increasingly worse, and conventional acidizing and plugging removal measures have had poor results. Therefore, this paper carries out research to provide a basis for effective plug removal in oil wells, to improve the productivity of polymer flooding oil wells.

In this paper, the component analysis of the plug samples from the benefit injection wells in the field was carried out. The clogging mechanism was studied through X-ray diffraction, scanning electron microscopy, energy spectrum analysis, infrared spectroscopy, and chromatography, as well as through dynamic simulation evaluation of plugs and dynamic displacement experiments of long cores. Through simulation experiments, the clogging mechanism is clarified and the blockage radius range was obtained by various methods such as inverse effect of comprehensive measures, well test interpretation, and empirical formula calculation.

The analysis results of the plugs show that the inorganic components of the plugs are calcium and magnesium carbonate scales, clay minerals and iron salt precipitation, and the organic components are the micelles formed by the crosslinking of trivalent metal ions. The greater the concentration of polymer produced, the greater the strength of calcium-magnesium scale aggregates and aluminum-iron-colloid elastomer, the greater the degree and depth of reservoir pore throat clogging, the larger the screen clogging area, which will even block the inlet of electric submersible pump. This will result in poor acidizing plugging effect and rapid decline in oil well productivity. Through various methods such as the inverse effect of comprehensive measures, well test interpretation, and empirical formula calculation, the blockage radius of polymer flooding response wells is greater than 4 meters. Based on this understanding, in the five wells plug removal measures, the unblocking radius and unblocking chemical agent system were adjusted and optimized. On-site application effect tracking shows that the plug removal measures have achieved good oil incremental effects, and the measures are all effective.

Through the classification and comparison of oil well productivity characteristics, formation water composition, output polymer properties and other characteristics, this paper established the identification mark of plugging of polymer-response wells. In addition, an analysis method for clogging was established to clarify the composition and formation mechanism of the clogging. Finally, the plug radius calculation method was established by means of backstepping the effects of plug removal measures and well test interpretation analysis.
Investigation on Insulated Tubing Corrosion in Nanbu 35-2 Multi-Thermal Fluid Project
Authors: Hao Tongchun , Zhong Liguo , Wang Cheng , Zhu Tianyin , Liu Jianbin , Sun Hongyu
Published: March 2021

Multi-thermal fluid simulation was conducted for offshore heavy oil reservoir such as Nanbu 35-2 in Bohai Bay Oilfield since 2008. Field well integrity testing result shows that Insulated tubing corrosion is found in many multi-thermal fluid injection wells. Insulated tubing corrosion has become one of the largest problems in the multi-thermal fluid project. It will negatively affect the development performance and also indeed a risky operation under high temperature and high pressure. In order to effectively prevent the corrosion problem of insulated tubing, the principles of insulated tubing corrosion and preventive measures are investigated. At first, temperature-pressure measurement and gas analysis were carried out in the multi-thermal fluid injection wells in Nanbu 35-2 heavy oilfield. Secondly, the corrosion laws of N80 and P110 steel in high temperature and high pressure CO2/O2 system were studied. At last, the corrosion mitigation effect of imidazoline corrosion inhibitor was evaluated through dynamic coupon test method. The results indicated that temperature, oxygen partial pressure and carbon dioxide partial pressure have effect on corrosion rate. Two peaks of corrosion rate of N80 and P110 steel appeared at 60°C and 180°C respectively, in the CO2/O2 system, even a little amount of O2 (partial pressure of 0.02MPa) could remarkably speed up corrosion. The corrosion rate drastically increased when carbon dioxide partial pressure exceeded 2MPa. The imidazoline corrosion inhibitor could lower the corrosion rate to 0.11 mm/a when the concentration was set at 750mg/L, and corrosion inhibition rate was high up 94.17%. The performance of the imidazoline corrosion inhibitor has been tested in field and results showed that the insulated tubing wasn’t corroded after using the corrosion inhibitor, which indicated that the corrosion inhibitor could meet the corrosion protection requirement of P110 steel in high temperature CO2/O2 system. The principles of insulated tubing corrosion in multi-thermal fluid injection wells is complicate because of multicomponent of multi-thermal fluid and high temperature and high pressure during its injection process. This study can provide basis for the design of insulated tubing in multi-thermal fluid project.
The Feasibility Appraisal for CO2 Enhanced Gas Recovery of Tight Gas Reservoir: Case Analysis and Economic Evaluation
Authors: Jia Ying , Shi Yunqing , Yan Jin
Published: March 2021

Tight gas reservoirs are widely distributed in China, which occupies one-third of the total resources of natural gas. The typical development method is under primary depletion. However, the recovery of tight gas is only around 20%. It is necessary to explore a new technique to improve tight gas recovery.

Injecting CO2 into tight gas reservoirs is a novel trial to enhance gas recovery. The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery of tight gas reservoir.

Taken DND tight sandstone gas reservoir in North China as an example, 34 wells of DK13 wellblock were chosen as CO2 Enhanced gas recovery pilot area with 10-year production history. Six injection scenarios were studied. Numerical simulation indicated that the recovery of the gas reservoir of DK13 well area was improved by 8-9.5 percent when CO2 content of producers reaches 10 percent. The annual CO2 Storage would be 62 million cubic meters (110 thousand tons) and the total CO2 storage would be around 800million cubic meters (1.5 million tons). After the environmental parameter evaluation of injectors and producers, the anticorrosion schemes were put forward and the feasibility evaluation and schemes of facilities were presented. The analysis results indicated that DK13 wellblock was suitable for CO2 enhanced gas recovery no matter geologic condition, injection & production technology and facilities. However, under the current economic conditions, DK13 wellblock was not suitable for CO2to enhance gas recovery. However, if gas price rise or low carbon strategy implement, the pilot test could be carried out.

In brief, CO2 could be an attractive option to successfully displace natural gas and decrease CO2 emissions, which is a promising technology for reducing greenhouse gas emission and increasing the ultimate gas recovery of tight gas reservoirs.

This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.
Adsorption Modeling of CO2 and CH4 in Nanopores Using Simplified Local Density Model: Application in Enhanced Hydrocarbon Recovery in Unconventional Reservoirs
Authors: Haghshenas Alireza , Hamedpour Mohammad
Published: March 2021

Adsorption isotherms of methane and carbon dioxide adsorption isotherms on shale samples are measured and the simplified local density (SLD) model is used to match the experimental data. The SLD equation also has the generic modeling capabilities to draw the deviation from bulk properties as a function of fluid-solid interaction energies. Still, compared to other available techniques such as molecular simulation, SLD has an advantage of mathematical simplicity and being run at shorter time interval. The model also has satisfactory potential to paint the underlying mechanisms for adsorption preference of one fluid component over the other.

The higher adsorption preference of carbon dioxide is reflected in the measurement data and the adsorption model is successfully used to fit the data. In addition to different critical properties of carbon dioxide compared to methane, the main important factor that may describe the high adsorption affinity of carbon dioxide is the fluid-solid potential energy. As shown in this work, the potential energy function shows deeper well depth, the deeper the well depth, the stronger the interaction between the fluid particles and solid surface.

By storing gas in high density, liquid like adsorbed phase, the adsorption mechanism can enhance the overall storage capacity of CO2 in deep reservoir rock relative to if there were a free phase alone.
Zero-Flaring Mudcake Removal: New Techniques for Efficient Natural Cleanup of Horizontal/Multilateral Open-Hole Wells
Authors: Alrabaei Rayan , Albarghouti Akram , Balto Abdulelah , Alkhaldi Mohammed
Published: March 2021

Effective mudcake removal is essential to restore the optimal well productivity/injectivity after different drilling operations. Typically, this objective is achieved by using harsh chemical treatments such as hydrochloric acid (HCl), organic acids and oxidizers. However, these methods have been limited due to associated high corrosion rates, high operation cost, and un-even mudcake removal. This task becomes even more difficult and very challenging in horizontal/multilateral wells. Organic acids and acid precursors have been also used to clean long horizontal wells following drilling operations. However, in long multilateral horizontal wells, fluid placement is considered one of the main challenges with chemical mudcake removal treatments due to accessibility to each lateral and reaching its TD. Additionally, the use of these treatments has poor health, safety and environmental (HSE) footprints.

This work provides a workflow and illustrates the use of an in-house designed zero-flaring flowback system to clean up recently drilled multilateral horizontal wells with water-based mud. The system consists of two upstream solid management systems, namely de-sander (cyclone), and sand catcher (filter). Downstream, the choke manifold, 4-phase separator, a downstream solid management equipment, and 3-phase separator are also included. Additionally, there is also a surge tank, as a backup flowback vessel to be used if needed to revive the well and offload any heavy fluids. This tank is used to initially help the well to gain the pressure momentum to naturally flow and offload heavy fluid present in production tubular. The cleanup campaign was successfully and safely completed for effective cleanup of more than 30 openhole horizontal multilateral wells without the use of any chemical treatments. The duration of cleanup operations was optimized using several techniques to effectively and efficiently remove existing mudcake.

This paper provides the operational criteria to achieve effective and adequate mudcake removal for horizontal/multilateral wells and restore its optimal performance. Different design parameters and tailored flowback programs will be discussed, which led to effective drawdown pressure to reach optimized natural cleanup of each well. The well simulated flow model was also considered and used as input to design each well specific flowback program and minimize the risks of erosion, solids settlement in pipeline and downstream facilities. As a result, each well cleanup duration was reduced to an average of 1-2 day, while achieving the maximum potential production rate of each treated well.
Geologic Modelling Using Augmented Reality
Authors: Boonyasaknanon Phathompat , Pols Raymond , Schulze Katja , Rundle Robert
Published: March 2021

An augmented reality (AR) system is presented which enhances the real-time collaboration of domain experts involved in the geologic modeling of complex reservoirs. An evaluation of traditional techniques is compared with this new approach.

The objective of geologic modeling is to describe the subsurface as accurately and in as much detail as possible given the available data. This is necessarily an iterative process since as new wells are drilled more data becomes available which either validates current assumptions or forces a re-evaluation of the model. As the speed of reservoir development increases there is a need for expeditious updates of the subsurface model as working with an outdated model can lead to costly mistakes. Common practice is for a geologist to maintain the geologic model while working closely with other domain experts who are frequently not co-located with the geologist. Time-critical analysis can be hampered by the fact that reservoirs, which are inherently 3D objects, are traditionally viewed with 2D screens. The system presented here allows the geologic model to be rendered as a hologram in multiple locations to allow domain experts to collaborate and analyze the reservoir in real-time.

Collaboration on 3D models has not changed significantly in a generation. For co-located personnel the approach is to gather around a 2D screen. For remote personnel the approach has been sharing a model through a 2D screen along with video chat. These approaches are not optimal for many reasons. Over the years various attempts have been tried to enhance the collaboration experience and have all fallen short. In particular virtual reality (VR) has been seen as a solution to this problem. However, we have found that augmented reality (AR) is a much better solution for many subtle reasons which are explored in the paper.

AR has already acquired an impressive track record in various industries. AR will have applications in nearly all industries. For various historical reasons, the uptake for AR is much faster in some industries than others. It is too early to tell whether the use of augmented reality in geological applications will be transformative, however the results of this initial work are promising.