bluuebunny/crossref_metadata_2025 huggingface dataset:
Transient Heat Transfer Model for Wellbore and Formation of Shut-In Offshore Oil Wells
Authors: Fang Tao , Liu Yigang , Bai Jianhua , Chen Huaxing , Zhao Shunchao , Li Yanyue , Pang Ming , Wang Yufei , Dong Peng
Published: October 2019

The heat exchange between wellbore and formation is unsteady after the oil well is shut in. As the shut in time increases, the fluid temperature in tubing would decline in a continuous way until it reaches a thermal equilibrium at the ambient temperature. However, there exist the potential risks of wax deposition, crude oil solidifying and poor fluidity in wellbore during the fluid temperature drop, especially for the waxy oil and heavy oil.

For resuming production of the well, the prediction of transient temperature is crucial. Taking account of the heat exchange between the fluid in tubing and formation/seawater/atmosphere for the offshore oil wells, the steady-state heat transfer before shut in is modeled based on heat balance. And the transient model for the shut-in stage is developed on the basis of Fourier's law of heat conduction, which can be solved by use of the finite difference method according to the initial condition and boundary conditions. To investigate the variation of transient wellhead temperature (WHT in short), the dimensionless WHT drop is defined.

For verifying the reliability and accuracy of the model, the wellhead and flowing temperature of a certain offshore oil well is monitored. The actual monitored WHT is 30.5 °C and the simulated value is 30.9 °C during the steady production stage. After shut in, the relative error of the simulated WHT is less than 5%, showing the model is credible. The variation of transient WHT is studied by applying the model as well. The results present that within just a few shut in hours, the WHT decreases rapidly. And then it goes down gradually to the air temperature. The WHT would almost fall to the atmospheric temperature after shut in 24 hours, even though the air temperature and liquid production before shut in differs greatly. The dimensionless WHT drop declines with the increase of water cut and keeps constant when the water cut is more than 40%.

This paper focuses on modeling of transient temperature for the offshore production wells after shut in and summarizes the law of temperature drop in wellbore and formation. It provides an important basis for making the flow assurance plan after the well is shut in.
Acidizing Done Right in Hot Offshore Wells: Case Study
Authors: Nikolaev Max , Kamaletdinov Bulat , Molero Nestor , Payne Courtney , Fernandez del Valle Julia , Daeffler Christopher , Dunaeva Anna
Published: October 2019

Treating deep hot carbonate reservoirs, such as those found in the Arabian Gulf, presents a series of complex and related challenges to achieve effective and uniform stimulation. Due to the elevated temperature and heterogeneous formation, achieving good reservoir contact with an acid system along the entire interval of interest requires robust treatment fluids that can withstand the harsh environment. Recently, a novel single-phase retarded acid (SPRA) system and an engineered degradable large-sized particulate and fiber-laden diverter (LPFD) were introduced in a well in the Arabian Gulf, yielding strong results for the stimulation treatment.

The SPRA, a 15% HCl-based acid system, showed excellent performance in a high-temperature environment (320°F). The fluid delivered similar friction pressures to unmodified 15% HCl, wormholing performance equivalent to emulsified acid without encountering the issues of fluid quality with respect to emulsion stability, and much higher dissolution power than organic acids and chelating agents. The pressure drop after the first acid stage was over 1,000 psi in about 60 min. After the second stage of acid, the pressure drop was close to 1,000 psi in about 30 min.

Previous stimulation jobs in the region indicated a need for a significant amount of traditional diversion materials to achieve an effective plugging of the leakoff zones. A novel degradable LPFD system was introduced, achieving a significant increase of injection pressure (~1,000 psi) across the perforations. In addition to the effect on the diversion pressure, the implementation of the LPFD system has helped to reduce the footprint in offshore operations, has simplified materials handling, and has delivered the most efficient diversion performance in bullhead operations compared to other diverters.

This article presents a novel method of stimulating deep hot offshore wells by combining an efficient SPRA and a unique degradable LPFD. These methods represent a step change to current practices and can be considered for effective stimulation in challenging carbonate formations.
A Novel Method to Characterise Time-Variation of Reservoir Properties: Experimental Study, Simulator Development and its Application in Bohai Bay Oilfield
Authors: Sun Zhaobo , Li Yanlai , Ma Kuiqian , Xu Jianchun , Zhang Guohao , Jiang Ruizhong , Pan Shaowei
Published: October 2019

For waterflooding oilfields, both the lab experiments and field practices have proved that the physical properties of water-flooding reservoirs would be altered due to the washing of injected water. This condition has not aroused enough attention. There is no proper approaches to describe the change of reservoir parameters against water flux in reservoir simulation. Most commonly used reservoir simulators (Eclipse, CMG, et al.) neglect the alteration of reservoir properties during simulation, and thus, lead to unreasonable history matching and production forecasting.

A new parameter known as Pore Cross-sectional Area Flux (PCAF) is introduced to continuously characterize the time-variation of a property during simulation. This new method overcomes the disadvantage of the previous characterization approach known as Pore Volume (PV), which is strongly dependent on grid size.

A new numerical simulation software in which reservoir properties are considered functions of PCAF is developed based on the black oil model, and the new simulator is validated against Eclipse. Furthermore, the effects of the time-variation of different parameters on the ultimate oil recovery are investigated. Finally, this simulator is applied to SZ-I oilfield in Bohai Bay to demonstrate how this simulator can achieve more accurate simulation.
Accounting for Adiabatic Expansion in Analyzing Warmback Temperature Signal After Cold-Fluid Injection
Authors: Hashish Refaat G , Zeidouni Mehdi
Published: October 2019

Temperature transient analysis has been evolved as a new alternative that can be adopted jointly with pressure transient analysis for reservoir characterization and surveillance purposes. In this work, an analytical approach is developed to characterize the reservoir using down-hole temperature measurements obtained during a pause in injection activity. The analytical solution is developed by solving mass conservation equation coupled with energy balance equation, which are subject to appropriate initial and boundary conditions. The solution is obtained using Hankel integral transformation to evaluate the temperature response with respect to time and space. The obtained solution identifies and evaluate: (i) the early-time cooling effect caused by adiabatic expansion of injected fluid in injection zone after injection stops and, (ii) late-time warm-back effect caused by heat flux from cooled unswept region and the surrounding cap/bed strata. Using early- and late-time asymptotic solutions, temperature inversion procedures are introduced in the form of appropriate graphical techniques to characterize the reservoir. Measured sandface temperature after injection is stopped along with the developed procedure are used for evaluating thermal properties of reservoir such as effective heat capacity and thermal conductivity, pressure diffusivity of the reservoir, extent of thermal front and initial geothermal reservoir temperature. The analytical solution results are validated against numerical results obtained via a thermally coupled numerical reservoir simulator. The analytical solution provides good agreement with the numerical results during forward modelling and inverse modelling. Sensitivity analysis is developed to investigate effect of wellbore storage, characteristics of reservoir and injection rate on the temperature behavior during shut-in.
Deep Autoencoder-Derived Features Applied in Virtual Flow Metering for Sucker-Rod Pumping Wells
Authors: Peng Yi , Zhang Jianjun , Xiong Chunming , Shi Junfeng , Zhao Ruidong , Zhang Xishun , Xu Dongping , Li Qiming , Deng Feng , Chen Shiwen , Liu Meng , Chen Guanhong , Wang Cai
Published: October 2019

With the depletion of reservoirs, it is inevitable that once very prolific conventional and unconventional wells become stripper wells characterized as producing no more than 35 barrels of liquid equivalent per day over a 12-month period. The conventional metering strategy is not economical for its huge investment in facilities, equipment, sensors, and ongoing maintenance compared to current low production. This paper presents an innovative method utilizing state-of-art artificial intelligent algorithms to predict the production rate from real-time IIot testing and producing data with very low cost and reliable accuracy.

Abundant real-time field and well data acquired from IIot and digital field facilities establish a fundamental foundation for developing a machine learning application. This paper presents a method to predict the real-time production rate from real-time IIot data. In our method, we start with constructing our datasets from different data sources by combining the dynamometer cards, pumping stroke and rate, pump, rod, wellbore and reservoir parameters as inputs and the corresponded production rate as targets. The machine-learning model contains two neural networks: first, a deep autoencoder to extract the feature representations from all the dynamometer cards, then another neural network combining all related features to predict the real-time production.

The deep autoencoder derived features from dynamometer cards are used as parts of inputs to further real-time production prediction models, which eliminate the disadvantage of conventional hand-crafted features. Hand-crafted features can lose important information whereas autoencoder is designed to minimize information loss by learning high level features that can be used to reconstruct the cards. The production prediction model with pump and producing data combining more informative abstract features generate good accordance with the history data. After tested testing and validating data in several fields in one operator’s fields in China, the model demonstrates very high accuracy and with R2 more than 0.92, MAE less than 0.5 of wells producing less 5m3/day, RMSE less than 1.6 of wells producing 5-10m3/day and RMSE less than 2.2 of wells producing more than 10m3/day. The model has also been tested on hundreds of newly producing wells and with error in 10%, compared with high resolution real-time metering equipment.

The method described in this paper can be fully utilized to metering the real-time production with ultra-low cost in wells as long as acquiring a real-time dynamometer card. With the fast development of artificial intelligence technology and expanding training datasets, artificial intelligence is a good choice to lower the investment and maintenance cost for conventional and unconventional fields in the low oil price trend.
Ultra-High Density Oil-Based Drilling Fluids Laboratory Evaluation and Applications in Ultra-HPHT Reservoir
Authors: Li Jiaxue , Li Qinghui , Li Ning , Teng Xueqing , Ren Lingling , Liu Hongtao , Guo Bin , Li Shaoxuan , Hisham Nasr-El-Din , Al-Mujalhem Manayer
Published: October 2019

Global energy demand has driven petroleum industry to develop hydrocarbon resources from extremely harsh formations. Ultra-high density drilling fluids are critical to successful drilling and completion practices in all of these wells. In this paper, potential weighting materials were systematically evaluated and screened to accomplish an ultra-high density oil-based drilling fluid system (19.62 to 22.12lb/gal) aimed to utilize in ultra HPHT conditions (>30000psi and >410°F).

Potential high-density weighting materials were evaluated. Properties (pure density, particle size/distribution, surface area etc.) were evaluated and compared. Special treatment was conducted to optimize properties of weighting materials. HPHT filtration tests under static and dynamic conditions were conducted at higher than 410°F and 300 psi. Real cores with an average porosity of 19% and an average permeability of 50 md were used in the filtration tests. Rheological properties, sag tendency, the volume of filtrate, and the filtrate cake characterization was measured before and after heating at 410°F for 16 hours.

Results revealed that ultra-micro manganese and ilmenite complex after suitable surface treatment could act as an ideal weighting material than ultra-pure barite or other materials, which could fail in rheology and sag measurement with such high temperature and density. Viscosity and filtration analysis confirmed the stability and reliability of this novel ultra-high density oil-based drilling fluid.

This study developed a challenged drilling fluid system under critical conditions, as well as established a systematical laboratory evaluation and screening procedure of weighting materials and contributed recommendations on how to utilize it in the fields.
Low Pore Pressure Hydraulic Fracturing Breakthrough in Sanga-Sanga: Simple Methods in Performing Hydraulic Fracturing in Low Pore Pressure Reservoir
Authors: Rachmanto Rian , Pasaribu Hendra , Widjarnako Andre , Halinda Debby
Published: October 2019

Pertamina Hulu Sanga-Sanga is operator of Sanga-Sanga block located onshore of the Mahakam Delta, East Kalimantan Indonesia that has been producing since 1970's. With recovery factor to date is approximately of 70% of its initial in place, hence Sanga-Sanga block has entered maturity. However much of remaining reserve is still locked in reservoir with lower permeability where conventional completion cannot economically produce these type reservoirs. Many technologies have been applied in order to produce at economical rate these reservoirs, including hydraulic fracturing.

Hydraulic fracturing has been applied in Sanga-Sanga since 1980 until 2005 as first campaign but faced with many failures amounting 85% of the job failed. After a thorough study in 2006, one of the finding of contribution of failed job is high fracturing pressure triggered by high frac gradient. The study suggests that hydraulic fracturing reservoirs candidates should go through depletion to lower the pore pressure and lowering the frac gradient in process. By applying this method the second campaign had been executed from 2007 until 2012 with varying results.

Several failed jobs were identified as result of inability of the well to recover most of frac fluid in formation due to reservoirs have been very depleted with pore pressure below 2.5 Ppg. From this finding it is deemed that reservoirs with pore pressure less than 2.5 Ppg are not suitable as hydraulic fracturing candidates and therefore losing opportunity in producing depleted reservoirs.

In 2015 another attempt on executing hydraulic fracturing in depleted reservoir (pore pressure of 1.89 Ppg) was done. By addressing fracturing design, fracturing execution and sand clean out and Nitrogen (N2) unloading post hydraulic fracturing job resulted in successful job. The result was well was able to increase its production by 4 fold.

This paper illustrates the approaches in hydraulic fracturing in low pore pressure reservoirs (less than 2.5 Ppg) that usually are excluded as hydraulic fracturing candidates. This paper also discusses the challenges in hydraulic fracturing that comes with the typical reservoir characteristic in Sanga-Sanga and solution addressed in overcoming these challenges to achieve the successful hydraulic fracturing job especially in low pore pressure reservoirs.
Artificial Intelligence Assisted Decision Support Center: Pilot Implementation in Onshore Indonesia
Authors: Pratama Raka Cahya , Siregar Raynold , Putra Adriyan , Wicaksono Arief Randy
Published: October 2019

For years, the oil and gas industry has been utilizing real-time sensors to monitor multiple parameters. In drilling operations, these sensors are highly important in achieving the well objectives. They provide data to guide the well execution and aid during the evaluation phase. The downside is the limited capability to identify operational anomalies. The latest popular strategy to mitigate this downside is using a Decision Support Center to obtain the most benefit from this data. Decision Support Center should be available for 24-hour operations and consists of multiple personnel to review data, provide path forward recommendation, and alert the field supervisor.

During these past years, most companies have optimized the number personnel to keep competitive in a low oil price environment. However, some knowledge has been lost during the process. On the other hand, the industry worldwide is entering an era of digital transformation. This triggers the need for artificial intelligence systems that can translate analog knowledge from personnel to digital data, analyze for execution anomalies from sensor readings, and provide feedback and recommendations to the end-users.

In one of largest mature onshore Indonesian blocks, a pilot implementation of artificial intelligence assisted Decision Support Center was developed. With limited time and cost, the project needed to be developed as fit-for-purpose. Thus, the system focused on the significant problem which historically caused million dollars in lost opportunity in the form of stuck pipe. A single stuck pipe event could result in a US$ 2.5 MM loss, which is more than 2 times the typical well AFE in this block. Beside surface and downhole sensors readings, subsurface prognosis, torque and drag model; operational best practices were also included in the system. Anomaly alarms were developed, including ECD limit by depth, pick up weight limit by depth, torque limit by depth, potential loss circulation zone, maximum allowable static time, and maximum allowable pumps off time. Whenever the sensor reading exceeds these limits, an automatic alarm would be generated and sent to the field supervisor, drilling superintendent and drilling engineer. As result, it only required 1 personnel per 4 rigs to maintain the process compare to 3-4 personnel per rig required with the conventional Decision Support Center process. This process successfully eliminated stuck pipe events though to the remaining of the drilling campaign of 56 wells, where the historical frequency had been 1 stuck pipe event out of 20 wells.

Future improvement in this system will utilize machine learning to develop anomaly alarms by gathering data from offset well operations. An additional benefit of this system is to implement it in workover operations.
Infill Well Placement Optimization Using Integrated Asset Modeling Technique
Authors: Lee Taeyeob , Jeong Daein , Jang Sangyup , Kim Junggyun , Mo Cheolhoon , Jeong Hoonyoung , Choe Jonggeun
Published: October 2019

Determining optimal infill well placements is a complex problem that depends on reservoir properties and specifications of well and surface network. A numerical simulation is often the most appropriate method to evaluate the feasibility of the candidates. An integrated asset model of A field in the Middle East is built that couples a subsurface reservoir model with a surface network model. The integrated asset model is used to find optimal locations of 10 infill wells which are scheduled to drill in the future.

This paper proposes a step-wised approach for finding multiple infill well locations considering constraints of surface network. Firstly, an optimization process is conducted for all infill wells using an evolution strategy. Next, the same process is repeated exclusive of some wells, whose locations are already determined from the 1st optimization. This step improves an efficiency of the optimization and therefore, gives increased cumulative oil production results. Finally, integrated asset models are constructed for the 5 best cases, and elevation profiles of flowlines and trunklines are extracted from a geographic information system (GIS) at this time.

The optimal well locations are quite far from previous producing wells. It is good for avoiding production interferences, although these locations have negative impacts on delivering produced fluid to a facility because of pressure losses. The integrated asset model could evaluate several effects simultaneously and could give practical infill well locations for the target field.
Mono Ethylene Glycol Regeneration System Upgrade
Authors: Kim Jonghyun , Scalea Paolo , Kim Jeongmoon , Kang Seongyoon
Published: October 2019

Objectives/Scope

This paper covers the Shwe Offshore Platform (SHP) MEG Regeneration System upgrade works implemented to reduce excessive MEG losses and improve operation of the System.

Methods, Procedures, Process

The SHP MEG Regeneration System processes MEG used in the topsides for hydrate inhibition in the Low Temperature Separators (LTS) and at the four subsea wells. Since start-up of production in 2013, SHP has suffered from excessive MEG losses and operational difficulties. Later in the field life, MEG injection to subsea wells was discontinued due to contamination with salts from formation water, and Kinetic Hydrate Inhibitor (KHI) injection was introduced. Extensive evaluation of data, laboratory tests and field trials were carried out to investigate the causes of the excessive MEG consumption and operational difficulties. The upgrade of the MEG Regeneration System was finally completed and put in service since May 2018.

Results, Observations, Conclusions

The followings have been identified as the direct causes for MEG losses and operational difficulties; Poor efficiency of Glycol-Glycol Heat Exchangers (HEXs), causing low operating temperature of the Rich MEG Flash Drum and poor condensate/Rich MEG separation, resulting in MEG losses via Flash Drum condensate outlet.Excessive condensate in the Rich MEG reaching the Reboiler and resulting in contamination of the Lean MEG and downstream section (injection spray bars).Low water loading in the MEG Regeneration System resulting in lack of reflux and MEG losses via Reflux Drum.MEG carryover from LTS to the Export Gas Compressor (EGC) Suction Scrubbers, caused by foaming in the LTSs.

In order to resolve the issues above, a number of modifications were implemented. New Glycol-Glycol HEX and a Liquid-Liquid Coalescer Filter were installed to provide better separation of condensate from Rich MEG. Also re-routing of the EGC Suction Scrubbers liquid outlet back to the MEG Regeneration System to recover the carried over MEG.

Significant reduction of MEG losses was achieved, in the range of 70%, and overall system performance has improved. The main outcome of such improvement is that the condensate content in Rich MEG has been significantly decreased to below 500ppmV from above 1vol% due to the increase of Rich MEG Operating Temperature in Flash Drum and introduction of the Liquid-Liquid Coalescer Filter.

Novel/Additive Information

This paper was written to describe the method used for resolving the problems with MEG losses, excessive condensate in the Rich MEG, and MEG carryover. It also explains the data evaluation, preparation, execution, and the results of the MEG Regeneration System Upgrade work.
Meeting the Strategy of Onshore Petroleum Exploration Based on Statistical Analysis of Operating Cost and Commercial Reserves in Indonesia
Authors: Abdul Azizurrofi Ahmad , Setya Buana Yosef , Bramono Triadi
Published: October 2019

In early 2016, oil price has fallen to its lowest level (30.32 US$/bbl) over the last 12 years. Since then, petroleum exploration and exploitation activities are decreasing worldwide due to high production cost and low oil prices.

As of December 2017, there were 431 Projects or PODs approved by government of Indonesia and the 327 of them were PODs that located in onshore area. This paper will evaluate and analyze the distribution of commercial reserves per projects and the operating cost to help Contractors to find the onshore area in Indonesia that has the highest commercial reserves and the lowest operating cost.

The purpose of this paper is, to divide the geographical areas of Indonesia into 5 different areas (Sumatera, Java, Kalimantan, Sulawesi and Papua)). Then, to collect the data that related with number & location of Projects (POD), commercial reserves and operating cost and then the project reserves (MMBOE/project) and project operating costs (US$/boe) are calculated and distributed to those aforementioned areas.

Based on the analysis and mapping of Petroleum Operating Cost and Commercial Reserves of 327 onshore Projects (POD), Sulawesi had the highest commercial reserves (64.00 MMBOE per Project) and Sumatera had the lowest commercial reserves (7.20 MMBOE per Project). As for the operating cost, Papua had the lowest operating cost (2.50 US$/BOE) and Kalimantan had the highest operating cost (10.10 US$/BOE) which remained lower than the current oil price (49.52 US$/BBL, average oil price January – July 2017). These analyses showed that the onshore area in eastern of Indonesia tends to have low operating cost and the high commercial reserves, which consequently mean that the onshore petroleum exploration and exploitation activity should be done by contractors in eastern area of Indonesia.

Finally, this paper is expected to provide contractors a quick look at oil and gas industry in Indonesia especially at onshore area and guide them to choose which onshore area of Indonesia to explored and also help them create their petroleum exploration strategy in Indonesia by considering on this information.
Digitalizing Performance Management with Business Analytics and Risk Based Planning
Authors: Okasha Qutaiba , Aladasani Ahmad , Al Dushaishi Mohammad F. , Ameen Ali , Nygaard Runar
Published: October 2019

A case study is presented in this paper that introduces a novel approach to Performance Management (PM) in an Exploration and Production Development Company (E&PDC). Typically, performance is measured at a functional level without sufficient attention to the validity of the Strategy, and the efficiency of the organization, or its leadership. Business analytics, and risk-based planning is used to improve the application of the business Strategy in an E&PDC. The case study described in this paper examines the Strategic performance, and the organization’s efficiency as part of the Performance Management system. Data Analytics was conducted on consolidated 12 years historical performance metrics to identify, the Health of the Strategy, correlations of different Performance Management metrics, and, leadership efficiency. Strategic outlook was developed using multi variable regression to slice, and dice business performance profiles, assess risk, as well as opportunity. Risk based planning is then conducted on the statistical results to quantitively rank the E&PDC enterprise risks. The results indicate significant diversity in the organizational structure, and associated workflow. Consequently, the functional performance in the E&PDC is variable, and is often downgraded by incomplete workflow, and inadequate organization efficiency. However, the shortfalls of the business performance whether in organization, or workflow presents a wealth of information that can be readily used to improve business performance. Therefore, work in this paper provides the opportunity to improve cost per barrel by up to 20%, a reduction of up to 30% in capital investments, and a up to 25% decrease of man-hours required to carry out core business functions. The benefits of aligning organization capabilities with the Strategy, and revisiting policy is underlined in this paper. The economic viability challenges facing the oil and gas sector today require a lean approach to manage business liabilities. This can only be achieved with measurement of functional, organizational and strategy, performance and the development of risk-based business plans that prioritize annual business plans.
Evaluating the Impact of Market Variability on Reservoir Behavior and Economics
Authors: Browning Jim , Gorell Sheldon
Published: October 2019

Market behavior is not always predictable: commodity prices can rapidly change; political and corporate strategies are dynamic. This variability in market forces may drive immediate and significant changes to the production plan. Unfortunately, large changes to production rates (up and down) can cause formation damage, permanently affecting reservoir productivity and reserves. Consequently, responding to market variability requires informed decision making and an effective communication process. Each reservoir has unique characteristics. Learning from the effects of operational changes improves the understanding of the reservoir and can substantially improve the decision-making process. Reservoir surveillance and simulation provide the ability to analyze, model, and forecast reservoir behavior throughout its productive life. This data acquisition and analysis provides insight necessary to determine mitigation and repair strategies as issues arise.

This paper reviews market drivers for different types of operating companies and associated operational responses. Reservoir impacts of various operational changes (production rates, methods and treatments) are described. Information sharing and effective communication across the organization are necessary for the effective development of a petroleum resource. To address this, common issues and a recommended decision making process are provided.
Hybrid Nano Acid Fluid Pulsed with Electrokinetic to Stimulate Tight Carbonate Reservoirs: A Novel EOR/IOR Method
Authors: Kim Minkyun , Haroun Mohammed , Rahman Md Motiur , Kobaisi Mohammed Al
Published: October 2019

This study characterizes the impact of hybrid nano-acid fluids (HNAF) to improve oil recovery from tight carbonate reservoirs. While acidizing creates continuous channels (wormholes), wettability alteration takes place by nanoparticles in penetrating through the tight pore throats and adsorbing on the surface of pore wall. In addition, it is validated that the application of HNAFs with pulsed electrokinetics (EK) effectively stimulates the tight formation, which is being investigated by dual energy computed tomography (DECT) scan, showing efficient wormholes. Methodology is divided into two parts. The fisrt part is to identify optimum concentration of hybrid nano-acid fluids by conducting IFT measurements. The second part is to verify the combined effect of hybrid nano-acid fluids with electrokinetics and relative contribution of acid, nanoparticles, and electrokinetics by conducting spontaneous imbibition tests, core flood experiments, and zeta potential data.

Selected HNAF formulations, such as SiO2-Acid (HNAF1), Al2 O3-Acid (HNAF2) and ZnO-Acid (HNAF3), produced a significant IFT reduction under HPHT conditions from 18 dyne/cm (formation water and oil) to 3.14 dyne/cm, 2.89 dyne/cm, and 4.14 dyne/cm respectively. When conducted with sequential application of EK, HNAF1 showed higher performance compared to HNAF2, followed by HNAF3, in terms of displacement efficiency (DE). During pulsed simultaneous application of EK, HNAF1 showed higher performance followed by HNAF3 and HNAF2. The DE and PE averaged at 9% and 180% during sequential application. The displacement efficiency recorded a significant increase in the case of simultaneous versus sequential application while requiring 27% less pore volumes injected. The zeta potential verified the coreflood (CF) ranking order through matched shifts in zeta potential before and after CF, which confirms a drastic alteration in wettability post flooding.

The summary of research presents promising potential to overcome the limitations reported from the previous studies, and improved the understanding of the application of HNAFs in tight carbonate reservoirs. This integrated study has assisted in successful formulation of HNAF assisted with the EK in lab scale.
Improving Horizontal Well Performance with Bottom Feeder Intake on Electric Submersible Pump in Gassy Wells, Offshore North West Java
Authors: Puspita Clarissa Tyas , Luciawaty Mery , Wirasupena Harisza
Published: October 2019

Oz is an offshore oil field with Electric Submersible Pump (ESP) as the main artificial lift system. Gassy well condition becomes a key challenge in this field as some ESP wells trip due to pump gas locking which leads to production deferment and ESP failures. The exploration for solutions to improve well performance by avoiding gas-locking conditions has gone through a steep learning curve and many adjustments since ESP firstly installed in Oz field. Starting from widely used conventional gas handling equipments such as gas separator and gas handler to application of multiphase pump on the ESP system. But none of those equipments have effectively eliminated gas-locking condition in some wells. This paper will present a new approach at Oz field to improve well performance by implementing bottom feeder intake application on electric submersible pumps in gassy well.

To analyze this problem, well production simulations were performed and found out that flow pattern on the lateral section or below the ESP completion was slugging at some well conditions. Due to the slugging flow pattern, the fluid hold up in the annulus might be reduced up to 30%. A large amount of gas volume will enter the pump when the slug reaches the pump intake. In such a case, neither gas separator or gas handler is able to separate the gas or condition the flow before going into a pump, which leads to the gas-locking condition in the pump. Bottom Feeder Intake (BFI) was proposed as a unique and versatile solution to handle gas when slug flow pattern occurs in ESP wells, which effectively reduces gas-locking condition on ESP and subsequently improves well performance on those problematic wells.

Electric submersible pump with combination of gas separator and bottom feeder intake were first successfully installed in several wells in 2016 and currently are still running. The combination of bottom feeder intake and gas separator have been progressively installed on some problematic wells since then. This application significantly minimizes gas-locking problems, avoids cyclic shutdowns, increases ESP service life, reduces deferred production activities and gives opportunities to increase the production from ESP wells. Through well production simulation and analyzing the effect of fluid flow pattern below ESP completion to pump gas-locking symptom, bottom feeder intake has been chosen as an effective solution to minimize gas-locking in gassy well.
Present Situation and New Problems about Deliquification of the Four Major Gas Provinces
Authors: Jia Min , Li Nan , Zhang Jianjun , Shi Junfeng , Li Jun , Cao Guangqiang , Wang Haoyu , Wang Yun , Zhang Yi , Liu Yan , Wei Meiji , Wu Cheng
Published: October 2019

More than 80% of gas reservoirs in the four major gas provinces in China (Changqing, Southwest, Tarim and Qinghai) are producing water, and the gas reserves involved account for more than 75% of the total.

On the basis of continuous monitoring of water production and deliquification techniques in the provinces, the following observations are achieved. Firstly, the severity of water production in the four provinces is getting increasingly higher, and big challenge is confronted in striving for stable gas production in the fields. The proportion of water-producing wells increased rapidly from 38.1% in 2011 to 49.7% in 2018, resulting in dramatic decrease in single-well gas production (by 20% -- 99%). Secondly, deliquification is the primary technique for stable gas production and improved gas recovery in water-producing gas fields. The number of wells where deliquification technique is applied accounts for 94.68% of the total gas producing wells. The incremental production by deliquification accounts for 63.56% of the total increment. Foam deliquification is the major deliquification process applied in the four provinces. In 2018, the number of wells where foam deliquification was applied accounted for 66.43% of the total number of wells with deliquification, and the incremental production accounted for 55.20% of the total increment by deliquification. The techniques such as plunger lift and velocity string deliquification are also being applied more and more.

Three new problems are identified with deliquification techniques in the four provinces at present. Firstly, with the maturing of the fields, there will be more and more strippers with some of them approaching to the end of their life, and foam deliquification will no longer be competent as the major deliquification process. Secondly, as a deliquification process for strippers, plunger lift has a big potential of wide application, but there are still many problems to be solved with it. It is urgent to systematically monitor and analyze its performance, with proposals to be put forward on the relevant researches and its dissemination. And thirdly, Tarim gas field is facing the fact that water production gets more and more serious, and the gas production is drastically decreasing. What is even worse, the current method has poor effect on water control, so it is urgently imperative to carry out comprehensive studies on water production and overall water-control countermeasure.

By literature investigation and on-site analysis for nealy a decade, it is found that the operation parameters of 33% of the strippers fall beyond the applicable range of foam deliquification. The effective solution to this problem is to disseminate the application of plunger lift to meet the constantly increasing demand because of more and more wells' deteriorating to be strippers.
Safeguarding Well Integrity through Vigilant Sand Production Monitoring and Surveillance in Digital Field
Authors: Mohd Shabarudin Ezza Shazana , Mokhlis Mohamad Mustaqim
Published: October 2019

Prevention is better than cure is the right phrase to express how important sand production monitoring and surveillance to protect well integrity which consequently help securing environment, people, asset and also reputation without causing unnecessary restrictions to the production performance. This paper showcases the benefits gained from utilizing an automated Digital Integrated Operations System, or "IO" to enhance the existing Sand Monitoring and Management (SMM) workflow.

Sand production will impose significant impact and key failure are mostly related to erosion and sand accumulation. Reactive management approach can be implemented in a faster manner should we have good surveillance. The IO was designed to provide critical information on the historical and current status and operating conditions of wells, production and injection equipment, as well as daily production and injection volumes based on data fed from the thousands of transmitters installed at the plant. The system is used for different applications related to production surveillance and optimization, and also includes sand management as a core module. For this purpose, it utilizes the SMM workflow by enabling visual monitoring of well sand count data and compliance to well sampling plan in the IO platform, and by performing daily computation of erosional rates together with remaining wall thickness on surface flowlines - achieved by combining live well parameters with latest sand count data, latest well test and erosion rate.

Upon stringent monitoring, two (2) wells were identified by IO to be under high risk and quick action was taken to manage the risk. From IO, number of times that each well had been categorized under severity were then be validated by checking in the input data. From well monitoring and surveillance, flowing tubing head pressure (FTHP) were seen lower than trending and bean size had been fully opened. Knowing that the well is prone to be producing high amount of sand and expose to downhole integrity issue, the sand production must be controlled before it reaches to the surface.

The immediate action was to choke down the well, monitor the FTHP, evaluate well test performance trending and most importantly increase the frequency of sand count. After doing so, the team observed that erosion rate has been reduced below the limit and sand count was also reduced. Simple action can be taken if we know what is the root cause in a timely manner. All this will be possible through IO. Visualization had been transparent, communication was enhanced, and collaboration boosted towards safe operation.
Identifying High-Performance EOR Surfactants Through Non-Destructive Evaluation of the Phase Behavior Microstructure
Authors: AlSinan Marwah , Kwak Hyung , Salomon Marques Debora , Kaidar Ziyad
Published: October 2019

Surfactant screening for enhanced oil recovery involves studies of fluid-fluid and fluid-rock interactions to optimize the surfactant formulation for the reservoir of interest. In this paper, we utilize low field nuclear magnetic resonance (NMR) technology to monitor the phase behavior microstructure of fluid mixtures developed for high salinity and medium-range temperature conditions. A surfactant mixture of unknown composition was selected since it was developed for high salinity and temperature reservoirs.

Surfactant performance was monitored over 20 days using phase behavior bottle tests. Crude oil was mixed with surfactant solutions of different salinities to study the different emerging phase behaviors. Salinity scans were carried out using synthetic seawater. Also, samples were aged at 25 and 68 °C to monitor the progression of emulsion phase behavior. In addition to visual inspection, NMR measurements, in the form of 1D brine profiles along the samples, were conducted to detect the observed dispersed phases throughout the aging process and evaluate the associated oil-water interfacial tension (IFT).

At both temperatures, all samples formed water-in-oil (W/O) and oil-in-water (O/W) emulsions, except for the 4.5% salinity sample at 25 °C. Also, at 25 °C, both types of emulsions were shrinking with aging while forming a secondary W/O emulsion in-between the two phases. On the other hand, at 68 °C, emulsion break-down was accompanied by the formation of a middle O/W emulsion for 3 and 4.5% salinities while a middle W/O emulsion was emerging in 7.5 and 9% salinity samples. For the 6% salinity sample, two types of secondary emulsions, W/O and O/W, were developing in the middle of the sample.

Low field NMR techniques provide a nondestructive and robust method of monitoring surfactant performance, including dispersed volumes, emulsion stabilization time, emulsion type and surfactant potential in lowering oil-water IFT. In addition, they are capable of microscopic phase behavior monitoring, which is not possible by conventional visual monitoring technique.
IoT Implementation on Artificial Lift System in the KS Brownfield in South Sumatra Indonesia
Authors: Hidayat Azis , Sujai Ahmad , Aryadi Yuzar , Fathurachman Ahmad
Published: October 2019

The world industrial revolution has entered industry 4.0, where cyber-physical systems monitor physical processes over the internet of things (IoT) and cloud computing. SCADA is one of area where the industry 4.0 can be implemented, which could swift the way of work to monitor and control wells production from human dependent to real time data dependent. However, the implementation of SCADA technology is usually constrained by expensive cost.

In the KS brownfield, ESP is the major artificial lift. Most of the ESP are controlled with variable speed drive (VSD) without being connected to online monitoring system. To check the ESP status and healthy pump condition, it requires extensive manpower for daily site visit. By using supervisory control and data acquisition, the ESP status and parameters can be transferred directly to the users. The GSM-cellular network in the KS field covers most the wells location. This network can be an option to optimize the initial cost impact in SCADA implementation. A single platform of SCADA with automatic notification and well modeling capability in web-based application is also prepared to provide clear analysis based on real-time ESP parameters and widely accessible.

Simple GSM modem installed inside the VSD box to transfer critical parameters on real-time basis through the internet. During the implementation, some issues especially related to modem communication device aroused which significantly gave negative impact in this project. To handle these issues, more schematic communication and modem modification then implemented to withstand certain unexpected condition. Automatic machine notification and intelligent alarm are also create great benefit to increase operator response time.

This paper will describe why this type of SCADA system is a fit to purpose solution for this typical brownfield with simple installation, relatively low cost, good communication performance and decent security.
LNG Tank Automation at Floating Storage Unit to Maximize Regasification Product at Peninsular Malaysia
Authors: M Jaini Mimi Juazlin , Tn Harun Tn Arif , Rahmawati Silvya Dewi , Suryajaya Bobby , Muhammad Mahanum
Published: October 2019

This paper discusses the tank management optimization or automation of floating Storage Unit vessels in Peninsular Malaysia. The objective of automation is to determine which tanks need to be emptied for the incoming cargo (unloading process) and for the gas product from the regasification to be maximized. The FSU and jetty regasification unit (JRU) are in the same location, and both are offshore. Therefore, efficient production strategic planning is required.

Tank management of the FSU unit has two procedures that must be fulfilled during the unloading and send-out activities: (i) The calculation must be developed beginning with the unloading – send -out activity. The activity is conducted when new cargo comes and fill the tank in the FSU (unloading). Meanwhile, the send-out activity is also conducted to manage high boil off gas (BoG) generation (re-condensation of the BoG) resulting from the unloading activity. The send-out activity must be conducted from the tank to the regasification unit. (ii) The send-out activity occurs after the unloading-send-out activity (previous activity) to fulfill the requirement from the regasification unit (nomination). The liquified natural gas (LNG) storage does not allow for mixed cargo to be stored in the same tank.

Automation will provide an optimum send-out plan from each tank and each FSU. Currently, the range of cargo volumes that comes to the FSU is between 130 to 145 K M3. Using the proposed method, larger cargo could be scheduled and maximum gas from regasification at the JRU increases. Tank management automation will consider the first-in-first-out (FIFO) method regarding unloading time, boil off gas (BoG) temperature condition, and tank send-out sequence to ensure FSU balance. The FSU balance must be considered for the safety of the entire LNG regasification operation. Automation will provide an indication for the inter-tank transfer strategy when the volume of the incoming cargo requires more space compared to the available space.

This is the first concept developed to create the best strategy for utilizing FSU and JRU units. The same concept could be implemented around the world for different cases, such as FSUs located offshore and JRUs located onshore, different tank sizes, and different regasification units.