bluuebunny/crossref_metadata_2025 huggingface dataset:
Single Phase Retarded Acid System with Degradable Fibers Unlocks Production Potential in Tuba Formation, North Kuwait
Authors: Al-Enezi Badriya , Liu Peiwu , Liu Hai , Kanneganti Kousic Theja , Aloun Samir , Al-Harbi Sultan , Al-Ibrahim Abdullah
Published: November 2019

A recent study showed that Tuba reservoir, a limestone-rich formation, has the highest oil in-place of all upcoming reservoirs in North Kuwait. This tight formation has three main layers - Tuba Upper (TU), Tuba Middle (TM), and Tuba Lower (TL) with several reservoir units alternating with non-pay intervals. The reservoir units contain significant proven oil reserves; however, production performance after conventional acid fracturing treatments has been historically subpar. As part of new development plan, two horizontal wells, one in TU and one in TL were drilled to evaluate the production potential of a new completion strategy and technologies.

This paper presents one such technology, a single-phase retarded acid system used as a pilot project study. In contrast with previous conventional emulsified acid systems, the single-phase retarded acid minimized tubing friction, thus enabling high pumping rates for the entire treatment. Alternating with the acid system, a viscoelastic surfactant-based leakoff control fluid system allowed the acid stages to reach deeper into the formation. To aid, degradable fiber technology was pumped in several stages to achieve near-wellbore diversion and further control leakoff into large natural fractures, thus improving the stimulated reservoir volume. These fibers are designed to completely degrade with time and temperature after the treatment. Delivery of the complex acid fracturing treatment was optimized in real time for each stage based on bottomhole pressure trend and response.

Combining a new single-phase retarded acid system with chemical diversion technology has proved to be effective in maximizing lateral coverage and etched fracture half-length. Post-treatment evaluation of TU horizontal well revealed the initial production was as much as 150% higher than offset vertical wells after conventional treatments with gelled acid and as high as 100% higher than a previous multistage horizontal well treated with emulsified acid. The TL horizontal well was just put into production recently and is showing encouraging results considering the lower reservoir quality compared to TU formation.

The success of this technique and technical combination delivered breakthrough results for this region and has engaged new interest in developing the Tuba reservoir.
Innovative Solutions to Manage Slug Buildup in Multi-Phase Pipelines through Bypass Pigging
Authors: Kollamgunta Saikiran , G.V.R.A. Srinivasa Rao , Singh Harendra , Kamal Faris Ragheb , Takieddine Oussama
Published: November 2019

One of the major challenges in multi-phase pipelines is to manage slug during pigging to ensure safe and smooth operation of downstream facility. The liquid slug accumulated during pigging can result in process upset, shutdown if the downstream facilities are not designed to handle the anticipated slug volume. This paper discusses the benefits of by-pass pigging to efficiently handle the slug volume resulting in optimal use of assets and without compromising the field production.

By-pass pigs are specially designed pigs with holes on the discs that allow part of the fluid to move from behind to the front of the pig. This design feature helps minimize the liquid slug accumulation in front of the pig and significantly reduces the slug volume as compared with conventional pigs. Dynamic Flow Simulator is used to analyze the performance of bypass pig. However, the use of bypass pigs involves careful assessment with respect to well fluids impurities such as presence of wax, solids or high asphaltenes which may block the holes and thus influence the operational efficiency.

The liquid slugs generated during pigging operation can cause severe operational problems in terms of level and pressure fluctuations in a separator leading to poor separation, potential liquid flooding, increased flaring, emergency shutdown and production loss. In order to minimize the slugging impact, sufficient buffer volume is provided in the slug catcher/separator to accommodate the slugs generated in the pipeline during various operations. However, considering surge volume in existing separators, Brownfield Projects can impose risk due to space constraints. To mitigate the risk, production levels are normally reduced during pigging operations leads to production deferment. However, during revamp of existing facilities for higher production capacity or changed operating conditions where existing equipment sizes impose constraints, bypass pigging has been shown to provide useful and practical solutions. This option can also useful in providing reduced slug catcher sizes for "Greenfield Facilities" as well. Very importantly, the bypass pigging operation eliminates production loss with no facility upsets. The benefits of this technique are established through transient simulations, before being adopted in facility design and operation. This paper discusses the related case studies.

This paper discusses the benefits of bypass pigging and the challenges to accommodate the increased surge volume in the existing slug catcher/separator system during pigging operation. The application of bypass pigging to limit slug volume is demonstrated using Dynamic Multiphase Flow Simulator and compares the results with conventional pigging operation. The proposed design solutions are based on NPCC's extensive and successful experience in tackling challenges in design of slug handling facilities especially in Brownfield projects.
Riser Design Automation with Machine Learning
Authors: Bhowmik Subrata , Noiray Gautier , Naik Harit
Published: November 2019

The objective of the paper is to investigate the optimal riser configuration through a comparison of two different riser design automation frameworks based on multi-objective optimizations using a Random Forest (RF) based metamodel coupled with Evolutionary Algorithm (RF-EA) and Radial Basis Function (RBF) based metamodel coupled with Evolutionary Algorithm (RBF-EA). The hybrid framework demonstrates the multi-objective optimization for minimizing material cost and minimizing fatigue damage along the riser.

Steel Lazy Wave Riser (SLWR) configuration is considered for the riser design optimization. The configuration consists of multiple design variables such as top angle, sag bend elevation, hog bend elevation, length of the buoyancy section, the module diameter and the layback distance. The riser configuration optimization is time-consuming and exhaustive due to nonlinear time domain analysis and due to a large number of load cases for extreme load and fatigue load analysis. Metamodel for the riser is the alternative option to use in the optimization algorithm instead of Final Element (FE) model for the dynamic analysis of the riser. Two different machine learning approaches, i.e. RF and RBF are used to develop the metamodels and coupled with Evolutionary Algorithm (EA) to form hybrid optimization method. Both the methodologies minimise both the riser cost and fatigue damage of the SLWR. Therefore, both the methodologies generate the optimal solutions which shows how design changes impact the trade-off between these two diffrent objectives. RF-EA provides a comparatively better configuration compared with RBF-EA.

The riser design optimization using machine learning assisted metamodel can save considerable computational time and require less need for design experience.
Exploration Challenges in the Northern Emirates: A UniQ Approach to Structural Definition
Authors: Trezzi Stefano , Glushchenko Anna , Vasilyev Pavel , Al Bulushi Abdullah Mubarak , Cox Edward , Al Hamadi Masoud Ahmed , Stewart Neil
Published: November 2019

This study summarizes the efforts taken to provide reliable structural delineations offshore the northern United Arab Emirates, an area where previous attempts failed to provide purposeful results.

With the employment of latest acquisition and processing techniques, a new high-density full azimuth volume shows clear uplift over legacy results. Structures never detected before are imaged, contributing to the de-risking of future well placement. These results are indicative of the challenges when acquiring and processing seismic data in the Northern Emirates.

The use of latest technologies was required to overcome several geophysical challenges, such as complex near surface, near-vertical thrust sequences and multiple faulting planes. All these elements contributed in generating extreme noise contamination, where a fast-varying geology with high dips made separation of primaries from noise one of the most difficult tasks.

Key pre-imaging technologies such as near surface characterization, 5D regularization to radial symmetry, as well as a tomographic velocity model building approach with iterative inputs from interpreters have been fundamental to converge to a solid velocity model that allows for a reliable structural imaging.

The work is particularly relevant for offshore exploration targets in the Northern Emirates, a region that has recently seen a growth in interest from local and international operators.
Reducing Pipeline Maintenance Costs, Time, and Resources Through Nonintrusive Diagnostics
Authors: Stewart Neil , Jack Graham
Published: November 2019

Maintaining pipelines in optimum condition is a costly and time-consuming process for operators, which requires many resources. To help ensure an asset remains in a good operational state, it is necessary to understand its condition to allow it to be maintained in an efficient and cost-effective manner. Current methods for deposit assessment are limited to intrusive methods, theoretical modeling, or external measurement. This paper details a compressive solution to these challenges using pressure wave analysis.

The method is based on analyzing the signal response generated by a pressure wave transiting the system as it is affected by geometrical changes in the system. By capturing high resolution pressure measurement on an ultrahigh speed logger, the generated pressure wave can be recorded for analysis. Applying acoustic velocity gradient modeling in conjunction with the effect of the of the system and the fluid parameters, the profile of the internal bore of the system can be accurately determined without the use of intrusive or localized external tools.

Detailed is how the theory behind the method is confirmed by results observed when used during a controlled full-scale field-trial environment in addition to subsequent activities to survey system profiles. A case study is presented, demonstrating that the method allows operators to make decisive asset performance decisions and review deposit buildup in a safe and cost-effective manner without having to stop production. The theoretical method for calculation of acoustic velocity for known system and fluid parameters is shown to be accurate within tolerances compared to the acoustic velocity gained in the field by recording the time of flight between two known points. It is demonstrated that restrictions can be detected to a level of accuracy of plus or minus three millimeters of thickness, verified by comparison with other inspection methods.

The described is a unique method for determining the internal profile of systems, which can offer significant advantages from traditional bore determination methods. It can provide information in a repeatable and verified level of accuracy without the requirement for expensive and time consuming intrusive intervention, this allows operators the opportunity to target remediation work in the most efficient and cost effective manner, therefore maximizing production uptime and throughput.
Geological Facies and Static Rock Types in a Highly Heterogeneous Lower Cretaceous Carbonate Reservoir from an Onshore Field in Abu Dhabi, UAE
Authors: De Benedictis Dario , Al Maskari Shaymaa , Al Hashmi Noor
Published: November 2019

A Lower Cretaceous reservoir in one of the Abu Dhabi onshore oilfields is the focus of this study aimed 1) to understand, predict and distribute the impact of diagenesis on the reservoir quality, and 2) to define the reservoir Static Rock Types (SRT). This will eventually help to define and predict the reservoir flow units to better frame strategies and choices for reservoir static and dynamic modelling, and to support the decision-making process for the oilfield business plan.

A fully integrated geological-petrophysical approach was used to carry out the study.

Nine geological facies are recognized in the reservoir and grouped in four main reservoir facies categories: 1) rudist-bearing facies, 2) grain-supported skeletal and Orbitolinid facies, 3) Bacinella/Lithocodium-coral facies, and 4) mudstone-supported facies. Rudist-bearing and Bacinella/Lithocodium-coral facies represent the best reservoir facies.

Rudist deposits mainly formed stacked patches- or sheet-like accumulations of reworked skeletal debris on platform top settings in the northeast of the field. In the main reservoir section, geological facies distribution mainly follows the hydrodynamic trend of the depositional settings. Rudist facies properties primarily depend on the depositional texture and the original shell mineralogy and structure (e.g. Caprinids vs. Caprotinids-Requienids).

Bacinella/Lithocodium-coral deposits form stacked shallowing-up peritidal cycles, representing the genetic units of the lower section of the reservoir. Evidences of epikarst in the uppermost cycles indicate the location of a major sequence boundary correlatable also to neighboring fields.

The impact of diagenesis appears strongly driven by the depositional facies characteristics, and a paragenetic sequence is proposed for this reservoir.

A link between geological facies features, including original grain mineralogy and depositional settings, and reservoir quality parameters is established, allowing the prediction and distribution of reservoir properties in the reservoir laterally and stratigraphically.

Seven SRTs are identified by integrating geological observations and the result of the petrophysical synthesis. SRTs definition closely follows the reservoir stratigraphic framework, allowing creating a two-fold scheme: two SRTs characterize the cyclic peritidal deposits of the Bacinella/Lithocodium-coral section, and five SRTs are identified in the upper rudist-rich section. Petrophysical evidences from MICP data also strongly support this approach.

A refined geological concept and stratigraphic framework is proposed for the reservoir to integrate the results of the sedimentological/petrographic analysis and petrophysical synthesis.

Through linking geology and petrophysics, a new robust scheme of SRTs is created to enhance the identification and prediction of the reservoir flow units.
WIZARD: Well Infilling Optimization thorugh Regression and Data Analytics
Authors: Formato Gaetano , Onzaca Christian , Molaro Simone , Amendola Alfonso
Published: November 2019

Objective/Scope

The definition of the locations of new wells in mature fields is a challenging problem especially in contexts of high geological complexity and low data reliability, when running fluid-flow simulations can be extremely difficult. For this reason, we develop an innovative Surrogate Reservoir Model, based on a data-driven process, which combines Machine Learning algorithms with spatial interpolation techniques. We call our approach WIZARD (acronym for: Well Infilling optimiZAtion through Regression and Data analytics).

Methods/Procedures/Process

WIZARD is a collection of different data-driven methods for the sake of definition of new infilling well locations on the basis of the expected cumulative oil productions (after a fixed target period) of unexploited areas of the reservoir. The first method, named COSMIC, is used to find a correlation between petrophysical well properties and well productivity through a regression algorithm.

The second method, that we call WIZARDMAP, uses spatial interpolation methodologies like K-Nearest Neighbours to estimate input petrophysical well data far away the existing wells and the trained COSMIC model applied to these interpolated data to predict the expected cumulative oil productions in unexploited areas of the reservoir. Finally, predictions of WIZARMAP model are compared with the ones given by another method that we call WIZARDROC, that is a predictive model trained by using only the cumulative oil productions of the existing wells and their locations.

Results/Observations/Conclusions

WIZARD workflow is applied to a highly faulted and layered reservoir with around 460 wells and 40 years production history, for which petrophysical and production data are available. Validation tests have been performed to evaluate WIZARD accuracy to forecast expected cumulative oil productions for new wells. WIZARD geological and physical soundness have been confirmed by experienced reservoir geologists and engineers, clearly showing that the methodology is reliable and therefore can be used for t least qualitative location screening of new infilling wells. This is furtherly confirmed by the satisfying match between the oil cumulative predictions of WIZARDROC and WIZARDMAP that has been obtained, indicating that the model can be reasonably used for predictive purposes.

Novel/Additive Information

WIZARD is an innovative Reservoir Surrogate Model that, combining Machine Learning techniques with spatial interpolation methodologies, is able to provide key insights for reservoir management and development plan, by suggesting the most promising locations for the new infilling wells.
Free Span Investigation of the Longest Subsea Gas Pipeline in Indonesia Using Remotely Operated Vehicle ROV
Authors: Erfando Tomi , Septriady Dela Agung , Apriandi Tengku Said
Published: November 2019

Based on the geophysical survey results, some part of the pipeline were found in free spans conditions. Interpretation from the geophysical survey shows that there were at least 181 free spans area along the pipeline with the length up to 200m and some of the pipeline was shown with span almost 3m above seabed. The ROV survey was then deployed to verify the free spans area and to check the other findings from the previous geophysical survey

Verification of freespan was conducted by setting up coordinates of the suspected area on the navigation software and ROV will start its investigation from the beginning of each free span to the end of it. Dual head scanning profilers, visual cameras which were installed on each side of the ROV and in front of vehicle were used to record pipeline condition along the suspected location. Position and depth of the ROV was overlaid to the video recording and the profile of seabed and pipeline along the inspected area were recorded in the navigation software

Information derived from the ROV inspection will then compared to the geophysical survey result and the final freespan condition were confirmed and results are tabulated for further rectification if required. Generally, there were 181 freespans locations inspected by ROV. Results of freespan from Freespan #1 at KP 3.638 to Freespan #181 at KP 233.978 are listed. There are some miss leading geophysical interpretation for the sample taken at KP 101.108 to KP 101.281, where from the geophysical survey was reported that the free span was found 150.1m but from the ROV visual inspection was found that the pipeline was set on seabed at some points with a maximum distance not more than 35m. Based on the ROV visual inspection, there were 29 freespans were found more than Maximum Allowable Span (MAS)

East Java Gas Pipeline Pipeline (EJGP) is the longest offshore gas pipeline in Indoensia. It transports gas receiving from Central Processing Plant on Pagerungan Island in Kangean Islands through the Madura Strait and onshore via Porong Sidoarjo to Surabaya with the total length of offshore part is 368km. The ROV is the first to be used to inspect this offshore gas pipeline.
A Novel Lwd Tool Based on High-Frequency Electromagnetic Wave Used for Determining and Ranging Reservoir Boundary
Authors: Teng Xinmiao , Sheng Limin , Zhang Liancheng , Ai Weiping , Gao Wenkai , Yu Dezhou
Published: November 2019

To increase reservoir-encounter drilling ratio while horizontal directional drilling, this paper presents a novel LWD tool based on the high frequency electromagnetic wave, which can get the accurate distance between the drilling tools and reservoir boundary. While horizontal directional drilling in the reservoir, the LWD tool mentioned transmits a modulated single-frequency pulse, the pulse width is about 10ns and the central frequency is about 350MHz, by the transmitting antenna. The high frequency electromagnetic wave is reflected on the interface of the reservoir and the cap because of the dielectric difference. The reflected wave can be captured by the receiving antennas and then be processed in the designed algorithm aiding in ranging the distance of the reservoir boundary in real time. A 2.0*1.0*0.7 meters clay sand, concrete ground and a saline bag with the conductivity in 60mS/cm are designed to simulate the situations likely to be in real horizontal directional drilling operations and to evaluate the detection capability of the LWD tool in a controlled situation. Under the different conditions and distances, the measurement range of the LWD tool is about 0.7∼2.0 meters and the accuracy is less than ±3 centimeters, a high accuracy for geosteering in horizontal directional drilling, which will be greatly helpful to keep the drilling bit drilling in the optimum position of oil or gas reservoir all the time to increase the reservoir-encounter drilling ratio.
Low Salinity Water Flooding in Carbonate: Screening, Laboratory Quantification and Field Implementation
Authors: Masalmeh Shehadeh , Al-Hammadi Mohammad , Farzaneh Amir , Sohrabi Mehran
Published: November 2019

In recent years, low salinity flooding has attracted significant attention as a new method for improving/enhancing oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of low salinity injection are available in the literature, which show a wide range of responses in the extra oil recovery, ranging from 0 to more than 20%. In this paper, we report experimental programs performed using cores and fluids from several reservoirs in Abu Dhabi with the objective of quantifying low salinity effect in both secondary and tertiary modes and to establish a procedure to screen reservoirs for their suitability for low salinity waterflooding.

To quantify the low salinity effect, multi-rate unsteady state flooding experiments have been performed in both secondary and tertiary mode using reservoir fluids and core material at reservoir conditions of 120 C and 4000 psi. All core floods were performed using 30 cm long and 2 inch diameter core samples. In addition, fluid-fluid interaction experiments were performed using fluids from more than 20 carbonate reservoirs in Abu Dhabi. The fluid-fluid experiments were performed to measure the water in oil micro-dispersion formed upon contacting crude oil with both formation water and low salinity water in order to screen ADNOC's oil reservoirs for suitability for low salinity waterflooding.

The fluid-fluid interaction experiments showed that a number of crude oil samples from carbonate reservoirs in Abu Dhabi were able to create micro-dispersion upon contact with low salinity water. These crude oils are called positive crudes in this paper. On the other hand, several crude oil samples did not show micro-dispersion upon contact with the same low salinity water, hence they are referred to as negative crude oils. Two positive crude oils and two negative crude oils have been used in the flooding experiments. The main conclusions of the study are: 1- The flooding experiments using positive crude oil samples have led to extra oil recovery upon injecting low salinity water, while the negative crude oil resulted in either no or little extra recovery, 2- The data base developed in this study is used for screening ADNOC's oil reservoirs for low salinity waterflooding based on fluid-fluid interaction and shows a significant potential of this promising EOR technology for carbonate reservoirs, and 3- The flooding experiments show up to 6.5% extra recovery in tertiary mode and up to 12.5% extra recovery in secondary mode.

The study presented in this paper demonstrates that the use of fluid-fluid interaction experiments and measuring the creation of micro-dispersion upon contacting crude oil with low salinity is a robust screening method for low salinity water flooding. Moreover, this screening method can lead to significant saving in both time and cost of running low salinity flooding experiments.
Understanding the Performance and Application Window of Autonomous ICD
Authors: Becerra Moreno Oscar , Gohari Kousha , Kendall Alexander
Published: November 2019

While it is understood that Inflow Control Devices (ICDs) can be an extremely valuable tool for reservoir management in certain applications, an engineering analysis is used to determine viability of ICDs for future developments. Typically, reservoir and production engineers use numerical reservoir simulation and/or steady state simulation to determine their applicability, evaluate various devices and configure their completions. Hence it is critical that the methods used to characterize the performance of the ICDs in these simulators are accurate.

For passive ICDs, the characterization is fit for purpose; however for Autonomous Inflow Control Devices (AICDs), despite their recent rise in popularity, the performance characterization has been limited to mathematically derived correlations that are adjusted to initial data. By using these mathematically derived correlations rather than physics-based modeling, the characterization is unable to predict critical flow for compressible fluids and critical flow caused by cavitation in the case of pure substance flow, such as water. By neglecting the effects of the physical phenomenas such as compressibility and cavitation, the simulation will result in higher gas production than reality for gas coning control applications and higher water production in thermal applications where the operational condition is close to water saturation.

Furthermore, fitting the correlations parameters for a wide range of fluid viscosities is complicated. This has led to several variants of correlation parameters that are dependent on specific ranges of viscosity. Hence, dynamic simulations can be complicated by the fact that the performance correlation factor has to be changed according to the fluid that is produced.

In an attempt to remedy these limitations, a typical AICD, considered an industry standard, was modeled using a mechanistic approach to capture the physics of the process as closely as possible. Existing sets of test data, some of which were publically available, for fluids ranging from 0.011 to 500 cP, were used to tune the mechanistic model and test the ability of reproducing the data.

The results have shown that the model has the ability to reproduce the flow loop test, effectively being able to predict compressible critical flow and performance of the device for a wide range of fluid viscosities. Furthermore, new experimental data was generated to test cavitation conditions that were included in a unified model. The unified model consolidates the expected operational window of the device, allowing accurate interpolation of non-tested conditions.
Gas Kick Simulation for Offshore Gas-Hydrate Reservoir Drilling
Authors: Liao Youqiang , Wang Zhiyuan , Pan Deng , Sun Baojiang , Duan Wenguang
Published: November 2019

In this research, a new gas kick simulator which incorporates the fully coupled heat and mass transfer model to describe the gas kick developing process, has been developed considering the unsteady gas–liquid–solid multiphase flow. Then, a series of numerical simulations are described to make a detail understanding of the gas kick developing process focusing on the variation of gas void fraction, pit gain and bottom hole pressure at various construction parameters. The numerical simulation results show that: fluid flow in annulus will change to gas–liquid–solid flow due to hydrate dynamic decomposition. What's worse, if there is no wellhead pressure control device, i.e. the wellhead pressure is equal to 0 MPa, the gas volume fraction and pit gain can reach 0.68 and 3.12 m3 at the wellhead, respectively. While, if the wellhead pressure increases to 0.5 MPa, gas fraction and pit gain only reach to 0.28 and 1.54 m3, respectively. Therefore, managed pressure drilling technology should be applied to hydrate reservoir drilling. On the other hand, if the mud inlet temperature is lower than 17.5 °C, which means a lower rate of hydrate decomposition, the gas volume fraction at wellhead can be safe and controllable. Compared with wellhead backpressure and inlet temperature, drilling fluid density has few effects on the gas void fraction in annulus. To sum up, in order to ensure safety and efficiency in hydrate layers drilling, a lower inlet temperature of drilling fluid and a higher wellhead pressure, such as 17.5 °C and 2 MPa, which mean a lower hydrate decomposition rate, can achieve the gas volume fraction at wellhead less than 10%. This paper provides some meaningful guidance in hydrate formation drilling process.
Evaluation of a New Barium Sulfate Dissolver and the Effect of the Presence of Calcium Carbonate in the Dissolution Rate
Authors: AlAamri Jamal , AlDahlan Mohammad , M. Al-Otaibi Fares , Al-Ghamdi Abdulaziz
Published: November 2019

Barium Sulfate, barite is commonly introduced into the oil and gas wells during drilling when used as weighting agent but it also can be formed at wellbore tubular during production as scale. After drilling, the barite in the wellbore and in the filter cake can cause erosion of well tubing during production, and should be removed. Dissolving and removing barite is a challenge because of its low solubility in water and hydrochloric acid. It can be removed by mechanical approaches, which includes scarping and jetting with foamed or viscose fluid to carry the heavy barite solid.

In this study, a new barite dissolving formulation was evaluated for its dissolving power and as barite and barite-based drilling fluid mud-cake removals. The dissolution rate at dynamic condition and in the presence of calcium carbonate was also evaluated for more than 72 hours reaction time. The study-testing scheme aimed to identify: the optimum solid to liquid ratio for maximum solubility, optimum soaking time at downhole temperature and solubility of mud-cake at optimum ratio and soaking time. Careflooding was also carried out to determine the rock-dissolver interaction.

The interaction between stimulation chemicals and formation rock is essential in order to understand these chemicals efficiency. The study results showed the average barite and mud-cake solubility was 276 and 167 lb/1000 gal in 24 hours at 270°F, respectively. 60% of the dissolved barite occurred in the first 5 hours soaking time. In the presence of calcium carbonate, the dissolution rate was dropped by almost 40%. The reduction started to be significant after 8 hours of soaking. Multi-stages treatments using 10 gallons of the dissolver per 1.0 lb of barite with 5 to 8 hours soaking time are expected to be more effective than one-stage treatment with a long soaking time.
A Novel Early Warning System of Oil Production Based on Machine Learning
Authors: Ma Kang , Jiang Hanqiao , Li Junjian , Zhang Rongda , Zhang Lufeng , Fang Wenchao , Shen Kangqi , Dong Rencheng
Published: November 2019

For mature oilfields which have entered into the high water cut stage, many stimulation measures are adopted in order to maintain the oil production. Those measures include drilling new wells, general measures, and strengthened measures. Even though the oil production increase when the measures conducted, it will cause different degrees of production decline in the next year. Due to the irrational composition of oil production in the matured field, abnormal production decline is becoming the primary problem for stable production. Establish an effective early warning system (EWS) is important to release production alarm and take necessary measures in advance. In this paper, the factors that can affect the abnormal decline are selected and the influence degree of different factors are compared by grey relational analysis. The machine learning was adopted to build the EWS. Three distinct forms of input data are considered to improve the prediction accuracy. By using the degree of deviation from normal as the input data for the prediction model have the highest accuracy. However basic machine learning model contains many input parameters which can't obtain easily. The number of input parameter is optimization based on the variation of accuracy under different input parameter number. In order to improve the prediction accuracy the artificial samples are added into the training process. The prediction accuracy of the final optimization model can reach 92%. According to the EWS the production condition of different reservoir is evaluated. The result reveals the possibility of the occurrence of anomalous decline in different reservoir which can effectively guide the oilfield production strategy. The EWS can be an effective tool in the oil production monitor in the mature oil field.
Seismic Data Management for Big Data Era
Authors: Pal Anik , Kumar Pranav , Shah Faridullah
Published: November 2019

Seismic data is one of earliest data acquired in a prospect evaluation and the data are utilized throughout the exploration and production stages of a prospect. With recent advances in the handling of big data, it is essential to re-evaluate the best practices in the seismic data ecosystem. This paper presents the idea to leveragingthe technology advancement in big data and cloud computing for Seismic data ecosystem with the aim to providing an improve user experience.

This new seismic platform would be capable of handling, managing and delivering the full spectrum of seismic data varieties starting from acquired field data to interpretation ready processed data. The system to have the following capabilities: Capability to entitle the right portion of data to every user as per interestOrganization of seismic data as per the business unitsData security by sharing data only with legitimate users/groups.Direct or indirect integration with all the data sources and applications who are consuming and/or generating dataSharing of and collaboration on data within company and/or across organization for shareholding partner, perspective seismic buyer for trading and relinquishment, regulatory agency resource certifying agencies and service providers etc. over limited network connectivity.Provide intergration/data deliverivey to End Users applications where this seismic data will be utilizaed

Implementation of Seismic ecosystem will enable: Sharing of seismic data by the acquisition, quality control, data processing and interpretation with user communities from one centralized storageCollaboration of stake holders in real time over an encrypted networkLeveraging cloud and mobility technology advancement for agility and interaction. The system will be connected and interactive yet has the power of complex high-performance computing infrastructure on the background.Data delivery and auditing to wider and more diverse user community that consumes data from different platforms.Secure data access based on organizational business units to make sure data does not fall into unauthorized hand.Reduction in seismic data turnaround time by reading and ingesting large volume of data through parallel input/output operation.Improved data delivery and map interface with contextual information out of the centralized data store.Augment traditional workflows with machine learning and artificial intelligence for example automated fault detection, etc.,

The proposed best practice aims to bring all of the different disciplines working with seismic data to one centralized seismic data repository and enable them to consume and share seismic data from big data lake. This is live and interactive when compared to traditional technologies of using the archive and restore system in standalone application.
In Situ 3D Characterization of the Texture of a Foam Flowing in a 3D Porous Medium
Authors: Ouali Chakib , Rosenberg Elisabeth , Barre Loic , Argillier Jean François
Published: November 2019

Two innovative characterization techniques, Small Angle Neutron Scattering (SANS) and High Resolution Fast X-ray Micro-tomography on a Synchrotron, have been combined to usual coreflood environments and X-Ray CT Scanner measurements in order to describe the texture of a foam flowing in an opaque 3D porous medium. SANS measurements give access simultaneously to the gas saturation and to the amount of gas-liquid interfaces developed per unit volume and therefore to the in situ specific surface area of the foam denoted S/V. In situ texture of the foam flowing in real 3D porous media is therefore measurable. Fast X-Ray micro-tomography 3D images of foam flowing in a porous medium give visual evidence of the presence of gas bubbles in areas where the flow rate is naturally slowed by the trapping phenomena and enable to describe and follow the phenomena of intermittent trapping at the pore scale.
A Decision Tree Regression Modeling Scheme for Estimating the PVT Properties of Kuwaiti Crude Oil Systems Using Incomplete Datasets
Authors: Almashan Meshal , Narusue Yoshiaki , Morikawa Hiroyuki
Published: November 2019

Accurate prediction of the Pressure-Volume-Temperature (PVT) properties of crude oils is required in the reservoir engineering studies and in improving the strategies of the oilfield development. For the past decade, machine learning has been successfully competing with the expensive and time-consuming experimental determination and the limited empirical correlations for estimating the reservoir fluid properties. In many situations, the PVT properties report may include some missing data that would limit the functionality of the empirical correlations. In this study, a decision tree regression model is proposed that is able to accurately estimate the PVT properties of crude oils using incomplete PVT reports. The proposed model predicts the bubble point pressure (Pb) as a function of the gas specific gravity, the oil API gravity, the temperature and the solution gas-oil ratio, based on a decision tree regression modeling scheme. An imputation technique has been applied to the incomplete datasets by using the mean value for each feature to fill in the missing values and then the complete dataset is fed into the predictive model for estimating Pb. Moreover, the feature importance for predicting Pb is discussed. The datasets used in building the predictive model are experimentally derived from 117 oil samples. Results show that the developed predictive model with the presence of missing data, outperforms the most commonly used empirical correlations in predicting Pb in terms of the average absolute percent relative error. Moreover, the built predictive model can be applied towards predicting other oil and gas properties by retraining the model with a new set of features, such as in the gas-liquid multiphase flow pattern identification. In addition, the predictive model can be integrated into simulators. In addition to the heuristic feature importance which can be determined by the decision tree regression model, this model has shown a significant predictive power with the presence of missing data in the input features. Furthermore, the dataset used in this study is novel and it represents oil wells of the Greater Burgan oil fields, in the State of Kuwait.
Extending the Application of Classical Conformance Plot to Assess the Water Flooding Plan
Authors: Haryanto Elin , Yersaiyn Saltanat , Khattak Iftikhar Ahmad , Shah Abdur Rahman
Published: November 2019

The use of Recovery-factor (RF) versus Pore Volumes Injected (PVI) plot to assess historical and ongoing water flooding strategy and its conformance is a common practice. However, this technique is rarely utilized to guide the future water flooding plan that are often assessed by dynamic modelling. The objective of this paper is to demonstrate an extended application of classical conformance plot not only for the typical use of historical and on-going water flooding performance evaluation but also as a tool to guide the future water flooding strategy.

A collaborative effort between different reservoir management team members were required to obtain the input parameters. This new workflow starts by applying the classic conformance plot technique on prediction scenario of production and injection data from numerical model. In this study, the water flooding conformance plot at layer level is presented. The plot was complemented by the theoretical recovery factor as reference of an ideal water flooding scenario. Subsequently, various injection prediction scenarios from dynamic model were added to the conformance plot template for detailed evaluation. The assessment includes evaluation of water injection rate, timing of water flooding development strategy application, location of injectors and various sensitivity analysis on the injection rates.

Some distinct shapes of conformance plots were recognized during the study. Views and opinion are gathered based on this study to identify the new use of conformance plot as a tool to assess the efficiency of different water flooding strategies. The lesson learnt from this study and the identified conformance plot shape can be beneficial to guide the direction of water injection plan to improve the overall field development plan.
Multi-Measurement Logging-While-Drilling Imager: New Enabler for Wide-Scale Comprehensive Geosciences Applications in Oil-Base Mud
Authors: Shrivastava Chandramani , Maeso Carlos , Wibowo Vera , Amir Irlan , Auchere Jean-Christophe , Maggs David , A Adrian
Published: November 2019

Borehole images have been widely used in industry for almost three decades for different geological and petrophysical applications; though these logs were often limited in application in the wells drilled with oil-base mud (OBM) due to resolution and coverage constraints against the downhole environment. Recent advances in technology helped address this issue with wireline logging; however, the logging-while-drilling (LWD) capabilities for high resolution borehole images in OBM remained limited thereby limiting any real-time applications of this data. The new innovative multi-measurement LWD imager provides game-changing enabler for wide-scale comprehensive solutions from drilling-efficiency till field development.

Singular image acquisition for subtle features at high resolution could often miss out on a lot of important events, thereby constraining the optimal characterization of sub-surface and downhole conditions. To properly understand, characterize and demystify the sub-surface, Industry's first multi-measurement imager was developed with high resolution capabilities in OBM; with ultrasonic and electromagnetic measurements physics.

Ultrasonic and Electromagnetic measurements are made at multiple frequencies by multiple sensors to ensure that the features on borehole wall are observed and resolved, both. The complementing nature of these technologies provide far better application capabilities, with multiple full-bore images being acquired simultaneously for apparent resistivity, amplitude and transit time by multiple sensors to overcome downhole operational challenges and variability of formation response without introducing complexity to the drilling bottom-hole assembly (BHA). The apparent resistivity images from electromagnetic measurements provide rich information of the sedimentological, diagenetic and structural features while the ultrasonic images are more sensitive to the near wellbore fracture, drilling induced features and borehole conditions.

Availability of the multiple measurements in real-time and relevant time lends the borehole image data for various applications, enabling drilling optimization, smoother and efficient operations and detailed geological characterization. Such comprehensive applications were not available earlier for wells drilled with OBM or any non-conductive mud.
Improving Cementing Success with Better QC: Field Case Studies of using a World-First Quantifiable Mix-Water Analysis Technique
Authors: Mahavadi Sharath Chandra , Curtis Nathan , Taoutaou Salim
Published: November 2019

Cementing is one of the most important steps in preparing a well for production. Critical parameters influencing the success of a cementing job are the concentration and the types of additives present in a mix fluid to prepare the cement slurry. However, it is extremely challenging to analyze water-soluble organics under oilfield operational conditions. In addition, with the complexity in chemistry of additives and mix fluids, it is also an analytical challenge to experimentally determine the quality of mix fluid and the slurry with standard analytical techniques such as high-pressure liquid chromatography (HPLC) or inductively coupled plasma spectroscopy (ICP). In addition to the general business need to verify chemical addition accuracy, in the field, the current practice to prepare mix fluid entails the addition of different additives either manually or using specialized liquid additive systems (LAS). Any human error in programming the LAS or manually adding the products yielding poor or no traceability for QA/QC could fail the cement job. This warrants the need for a reliable and field-robust method of quantifying additive concentrations in the mix fluid.

To address this challenge, we developed a workflow using electrophoresis to address this issue to support operations. Electrophoresis uses an electric field to separate and quantify the components of a single fluid or a mix-fluid additive system. More importantly, we can simultaneously detect and quantify multiple chemistries in a single run. We have developed methods to analyze and quantify all the ingredients in an aqueous fluid system. This includes organics such as surfactants, natural and synthetic polymers, organic acid, and the inorganic ions that are common in seawater and most base fluids in the additive system.

In the first step, we developed a method to analyze a single additive. This method addressed the issue of analyzing organics in aqueous fluid and demonstrated the applicability of this technology in determining the quality of the additives in terms of contamination. In later steps, the method was expanded to analyze and quantify dispersants, multicomponent retarders, and antifoaming agents individually as well together in a single run. Our study clearly demonstrated the electrophoresis technique can quantitatively differentiate multiple additives in a mix-fluid system while simultaneously estimating their respective ratios in the system. The developed method was applied to a mix-fluid system to identify a missing additive that led to the failure of a critical job.

Overall, a simple and reliable technique is introduced to determine the quality and composition of additives and the mix-fluid system composition to enhance the reliability of existing processes and thereby improve the success rate of cementing jobs. Examples from the field will be presented.