bluuebunny/crossref_metadata_2025 huggingface dataset:
Utilizing State of the Art Computational Intelligence to Estimate Oil Flow Rate in Artificial Lift Wells
Authors: Khan Mohammad Rasheed , Tariq Zeeshan , Abdulraheem Abdulazeez
Published: October 2018

Production rate is the single most important parameter that indicates performance of wells to subsurface/reservoir engineers so that they can efficiently monitor as well as optimize the behavior of the system (well and reservoir). Ironically, production rate in individual wells is not monitored usually in real-time, and wherever they are, flow transmitters are employed which carry their own inherent errors when multiphase flow occurs. Therefore, as an industry practice, daily conditions and well tests data is utilized to determine flow rates using developed correlations like Gilbert's. Nevertheless, the effectiveness of such correlations has been reduced due to lack of frequent production well tests and operational technical and cost issues.

For this reason, a model that can predict fluid rates, gives great advantage to the production engineers towards optimizing the well performance in real time. Accordingly, this paper focusses on adapting computational intelligence algorithms, to predict oil flow rate in artificial lift oil wells, which is robust, simple and can be applied universally. This study utilizes multiple computational intelligence (CI) techniques, which have not been utilized previously for this topic, namely; Artificial Neuro Fuzzy Inference Systems, Support Vector Machines alongwith Artificial Neural Network.

Separator production test data were acquired from a South Asian oil field operating on gas lift; followed by data cleaning and data type reduction to prepare the data for input to computational intelligence system. Consequently, only the readily available well head parameters were finalized to be used as the inputs. The output/target data was the separator measured oil rate. All the techniques are compared rigorously with each other and with currently used empirical models based on average absolute error and coefficient of determination. The analysis of the outcome of this work shows that the new model predicts oil flow rate with an accuracy of 98%, interestingly, example of such accuracy is not found in the current literature.

The results of this study show that the ANN outperforms all the current empirical correlations. This effort puts forth an industrial insight into the role of data-driven computational models for the production reconnaissance scheme, not only to validate the well tests but also as an effective tool to reduce qualms in production provisions.
Distributed Fiber Optic Sensing – A Technology Review for Upstream Oil and Gas Applications
Authors: Hveding Frode , Bukhamsin Ahmed
Published: October 2018

Real-time downhole measurement is essential for monitoring and optimizing well performance. For advanced wells, this enables zonal flow evaluation which leads to production control adjustments and ultimately closed loop optimization. The challenge is to turn these real-time measurements into real-time decisions for effective reservoir and production management. Optical fibers provides a great opportunity to achieve this in an economic and safe manner. This is because fiber optics is a non-intrusive tool that has the ability to detect acoustic and thermal effects anywhere along the well with very high frequency sampling both in terms of space and time.

The paper will establish the basic understanding of distributed measurement principles. Then, it will cover the different installation methods based on the parameter of interest. The fiber deployment can occur during initial well construction, or after completing the well as an intervention. The remainder of the paper focuses on different possible application of Distributed Acoustic and Temperature Sensing (DAS and DTS) that strive to solve day-to-day oil field challenges. The task of using real-time fiber optics measurements to monitor well performance is very complex and requires involvement from several disciplines within an organization. To illustrate the complexity of this task, we discuss the application of using distributed measurements for production and injection profiling as an example. An overview of algorithms commonly used to interpret flow from DAS and DTS measurements is presented. Furthermore, the use of DAS and DTS for sand detection and wellbore integrity applications is explained. Each application is supported with examples with the aim to provide reservoir and production engineers guidance to identify appropriate solutions for their challenges.
Expandable Liner System Provides Option for Repairing Corroded, Small-Diameter Casing
Authors: Benzie Scott , Huey Taylor , Cooper Charlie , Bufkin Christopher
Published: October 2018

Long, expandable liners offer practical solution for restoring well integrity in small-diameter wells with severe corrosion problems. Previous options for repairing these wells required running a tubing string to the producing interval, with a restrictive ID that limited production rates. New expandable liner technology, which has been proven in relining horizontal well sections exceeding 4500 ft, can be installed over the full length of vertical wells with small-diameter casing, sealing damaged areas with minimal ID reduction. The system includes packers and nipples that enable completion without a tubing string. In addition to extensive experience in North America, the system has been used successfully in Saudi Arabia to install a 315-ft casing patch to seal a corroded section in a demonstration well.

Many producing oil and gas wells in Saudi Arabia and throughout the Middle East were completed with cost-effective 4.5 in or 5.5 in production casing. Due to the casing's small diameter, options to repair corrosion or other integrity issues are limited. Running a production tubing string with completion packers can be costly, and the restricted ID can limit production rates. Expandable liner technology, originally developed to install casing patches of a few hundred feet, has been enhanced to enable installation of continuous expanded liners that can extend beyond 5,000 ft.

The liners are comprised of high-performing expandable alloy rated for high-H2S service and incorporate expandable threaded connectors. The liner is run to the desired depth and is expanded from the bottom using a downhole hydraulic jacking system to initiate the expansion and the rig's draw works to finish it. In typical 4.5-in casing, the resulting internal diameter is 3.4 in. The liner system includes metal-to-metal seals at top and bottom and can be fitted with production packers and nipples for gas lift valves, as required.

The expandable liner system has successfully addressed integrity problems on more than 100 wells. Recent applications in horizontal wells demonstrated the efficient installation and consistent expansion of the liner. Horizontal liners in excess of 4000 ft were expanded in an average of 29 hours and maintained integrity during hydraulic fracturing. The system also was used in Saudi Arabia to repair a corroded 300-ft section of 4.5-in casing in a producing well, with good results.
Knowledge Transformation to Develop Young Local Talent to be a Professional Workforce
Authors: Nugraha Budhi , AlKhaldi Latifah Kulaib , Al Ali Wassan Adel , Kashif Muhammad
Published: October 2018

A strategy to develop an efficient and effective workforce is to discover and attract the best candidates from our host countries and provide them with the best method of knowledge transfer and more opportunities to be nurtured to be a part of the business growth in the current and prospective future of the company. Various methods of training have been introduced and conducted with different approaches, however not many of these techniques are successful in grooming the young talent to be a potential next generation of the global industry.

The successful key of any training method is not only decided by the content of the training material, but there are some other factors that lead to the successful transfer of knowledge. The trainer can be a mentor and role model and a person that can motivate themselves and the trainee. This trainer should create a good ambience while transferring the knowledge so this process can be more effective, efficient and fun. Several other processes for transferring knowledge include: Self-Understanding – Delivery – the combination of visual, vocal and verbal. The delivering of information is not just about the content of what we say, but it is also related to how we say it, and the way we look when we say it. Vocal tone and body language of the non-verbal aspects influence the actual verbal message. This process also persuades the audience to follow a direction without denial. This can be done by creating a condition where the audience follows the direction because they are tempted with the effect offered in the statement. The strength of charisma from the trainer can also impact the success of this method.

To provide opportunity and development of young local talent, some companies have been adopting a strategy of knowledge transformation method. The recruitment process is done by using a variety of tools/methods and other tests to assess the skills and the candidates' competencies. Then the usage of both formal and informal combination training is done to progress careers and employee excellence. This execution showed an overall increase in the knowledge transfer. The backing of this method has helped them to quickly contribute to their departments or organizations by handling their regular duties in a shorter period of time.

Motivation is needed to attract the energy of young people so that the delivery of information can be done effectively and efficiently. When the process is well underway, the next thing is how the knowledge gained can be used in their professional lives so that it can be useful in developing their ability to be a more professional and dynamic workforce.
Carbonate Rock Resistivity Index Measurement Using Equivalent Rock Model
Authors: Tariq Zeeshan , Mahmoud Mohamed , Hassan Amjed , Khan Mohammad Rasheed , Sadeed Ahmed
Published: October 2018

The applicability of Archie's relation depends on the link between pore structure and resistivity of the rock, and because of this relationship, the rock maybe classified as Non-Archie. Keeping this factor in view, for carbonates, the intricate pore systems, the application of Archie's law becomes invalid and any estimate of water saturation using Archie's equation will most likely yield erroneous results. Many scholars and researchers have attempted to come up with models linking well logs and laboratory data to estimate water saturation in complex pore systems. To appropriately capture the conduction behavior of a rock is aimed at and the conduction mechanism is then related to not only the pore geometry but also other petrophysical factors including wettability and the existence of conductive exterior minerals. For complex lithologies, resistivity index curves cannot be accurately defined by Archie's law, and investigations at lower water saturation values are required to describe the non-Archie behavior.

The shape of the RI curves varies quite considerably and an attempt to describe the variation qualitatively as well as quantitatively requires the use of either dual or triple conductivity models. In these models, the pore systems are linked with each other electrically in series or parallel, in addition, a combination of the two is also possible. This enables the use of simply two of the three adjustable parameters to adequately model the experimental outcomes.

This study, presents a saturation model for dual porosity systems. Having NMR data will enable the use of this model to determine water saturation by utilizing the volume fraction of each contributing pore system (Macro and Micro) derived from NMR logs. Furthermore, this work also examined the effects of various influences on the electrical constraints which included cementation factor, the shape factor for the lithology and saturation exponent.
Successful Logging Operations through Y-Tool; Challenges and Lessons Learned On Restricted Completions
Authors: Al Zahrani Ahmed R. , Kalu-Ulu Torty C. , Al Nasser Ahmed N. , Al Yami Salem F.
Published: October 2018

Artificial lift utilizing Electrical Submersible Pump (ESP) supporting operations have evolved from pump installations with no access to the completion zone to the point where rigless logging intervention operations can access the lower wellbore using either coiled tubing or wireline. Access to the completion zone has been accomplished through the installation of Y-Tool and a by-pass leg in conjunction with the ESP.

The major challenge is to have the Coil Tubing (CT) plug seal assembly located on the coil otherwise a damage to the seal assembly is expected and consequently a fluid circulation might take place. CT conveyed production logging requires a CT plug to prevent production circulation across by-pass section while operating the ESP. The circulation is prevented by the seal assembly which exists in the CT plug and located on the coil tube. The Bottom Hole Assembly (BHA) consist of CT plug which included connector, sleeve and bottom crossover, all covered by the CT plug external body which has the seal assembly in addition to the Production Logging Tool (PLT). Changes in tools design and profiles allowed for a successful logging intervention into these Y-tool equipped wells while gathering required well logging data.

The paper presents technical and logistic challenges during rig-less logging operations on wells with a Y-tool and a by-pass leg with complicated downhole configuration including small restriction and dual pump layouts. Examples of both impaired and successful operations will be reviewed with challenges and lessons learned, including the changes made to allow the tools for logging activities. This paper will provide a path forward to well access and surveillance while ensuring adequate isolation during logging operation.
Assessment of Fly Ash as a Potential Demulsifier for Highly Stable Water-In-Crude Oil Emulsion Produced in the Petroleum Industry
Authors: Adewunmi Ahmad A. , Kamal Muhammad Shahzad
Published: October 2018

The quest for smart and cost-effective demulsification materials to separate water-in-crude oil (W/O) emulsions is highly desired in the petroleum industry. In this paper, an assessment study was conducted on the potency of coal fly ash (CFA) as a demulsifier for W/O emulsions. To our knowledge, this is the first study reporting CFA as a demulsifier for highly stable W/O emulsions. W/O emulsion samples were prepared without using any conventional emulsifier. Asphaltenes in the crude oil acted as an emulsifier and stable emulsions were produced. Six W/O emulsion samples of the same crude oil to water volume ratio (4:6) were formulated. A reference sample was selected for comparison during demulsificat ion. Demulsification tests were performed at room temperature (25 °C). Demulsification results obtained via the bottle tests showed that the reference sample (blank) without CFA remained stable without water separation after 48 hrs while the addition of various CFA quantities (1 % to 7 %) brought about separation of water from the oil phase. Separation of water was observed to have increased with increasing CFA addition in the emulsion. Water separation continued for each sample until around 24 hrs when equilibr ium was attained, and water separation remained constant. The W/O emulsion containing 7 % CFA displayed the highest performance with demulsifica tion efficiency (DE) of 96.67%. Demulsification comparison test results between CFA and a commercial demulsifier (poloxamer - 407) using same concentration and under room temperature showed that CFA was capable of separating water better than this commercia l demulsifier. This observation indicates that CFA can compete favorably with many commercia l demulsifiers available in the market. Additionally, the outcome of demulsification efficiency of 7% CFA at elevated temperatures (i.e., 60 °C and 80 °C) was around 98%. More importantly, the separated water at these elevated temperatures was clearer and contained lesser oil floccules than the separated water phase observed during demulsification tests conducted at room temperature (25 °C) condition. Shear rheology measurement reveals that CFA addition altered the viscoelastic characteristics at the crude oil/water interface at an aging time of 10 hrs and 55 mins. Viscous modulus remained stagnant while elastic modulus dropped significantly. Optical morphology revealed the phase transformation in the as-prepared W/O emulsion before and after the addition of CFA particles. The possible mechanism governing the demulsification of W/O emulsion driven by CFA particles was proposed. It is believed that this work will be relevant to petroleum exploration and refining operations.
New Insights Into Carbonate Matrix Stimulation From High-Resolution 3D Images of Wormholes Obtained in Radial Acidizing Experiments
Authors: Aidagulov Gallyam , Qiu Xiangdong , Brady Dominic , Abbad Mustapha , Onel Yener , Ewert Uwe
Published: October 2018

Usually, carbonate acidizing is studied by conducting linear coreflooding experiments in which a hydrochloric acid (HCl) solution is injected into small cylindrical core plugs, such as 1.5×6 in. (diameter×length) plugs. Results from these conventional experiments have provided extensive information on acidizing and wormholing mechanisms, but under conditions of essentially 1D flow along the axis of the plug. Meanwhile, field acidizing scenarios dictate radial (divergent) acid flow conditions around the openhole wellbore, and these conditions influence wormholing aspects such as initiation, branching, and death, in a way that cannot be simulated in linear coreflooding. In this study, we analyzed the results of large-scale radial acid injection experiments to advance understanding and characterization of wormholes created during matrix acidizing treatment.

We analyzed the results of high-energy X-ray CT scans for three 20×16×16 in. block samples of Indiana limestone from our recent radial acidizing experiments with HCl. CT scans were done for complete samples, and 3D images of internal dissolution patterns were built. Each 3D image consists of submillimeter-size voxels to capture fine details of individual wormholes.

The obtained 3D images of acidized blocks allow us to observe from various angles the details of the wormholes obtained in the three experiments, which demonstrated wide pore-volume-to- breakthrough (PVBT) range with three different injection rates. Also, variation of the CT number reveals the presence of depositional layers in all block samples, and the obtained CT images were used to interpret the effect that rock layers might have on wormhole penetration at different injection rates. Further, the built voxel models were used to calculate the radial distributions of dissolved rock volume, which otherwise are not obvious for such complex branched structures as wormholes. We observed how varied experimental conditions affected those distributions. The radial distributions were found very similar across the samples, which suggested the way to detect the effective wormhole penetration depth.

Radial acidizing experiments represent more closely the real conditions of wellbore acidizing; however, only a few radial acidizing experiments have been published to date. In this study, we enriched the results of our recent radial acidizing tests with high-resolution 3D CT images of the created wormholes which are quite rare considering the size of the acidized blocks. In the absence of field techniques to observe the wormholes downhole, CT images of the radially acidized laboratory samples provide valuable information about the appearance of wormholes, as well as quantitative data to validate models of wormhole growth and detection. Particularly, analysis of the obtained images showed how wormhole density responds to changing experimental conditions.
ASP Flooding: A Solution for Chemical Enhanced Oil Recovery in High Temperature, Low Salinity Reservoir
Authors: Hongyan Cai , Jie Cheng , Jian Fan , Hexin Luan , Qing Wang , Wenli Luo
Published: October 2018

Presently, field application of Alkali-Surfactant-Polymer flooding (ASP) has achieved great technical success with incremental oil recovery more than 20%. The synergistic effects induced by the three components, alkali, surfactant, and polymer greatly activate remaining oil after water flooding.

With the depletion of oil resources, ASP technique expanded to reservoirs having harsh conditions, such as high temperature, high salinity, low permeability, and heavy oil. For such oilfields, severe conditions bring great technical challenges to chemical agents, making it more difficult to obtain a suitable formulation than that in a conventional reservoir.

The ASP flooding feasibility study was conducted for a massive reservoir with high reservoir temperature ranging from 80 °C to 85 °C and low salinity less than 3000 mg/L. Various evaluations, including polymer testing, surfactant screening and evaluation, long term thermal stability, phase behavior were conducted in the laboratory. Then, the performance of optimized ASP formulation was tested by two runs of core flooding.

Through detailed in-lab study, thermal tolerant polymer and surfactant were selected with satisfying performance. Sound emulsification was observed in phase behavior study of Alkali-Surfactant (AS). ASP flooding utilizing weak alkali Na2CO3 was recommended for such high temperature, low salinity (HTLS) reservoir. Results from core flooding tests demonstrated an incremental oil recovery range from 16.89% to 20.38%. ASP shows promising technical potential for such low salinity reservoir.
Reducing Excessive Water Production Associated With Gas Hydrate Reservoirs Using a Thermal In-Situ Heating-Inhibitor Method
Authors: Fakher Sherif , Elgahawy Youssef , Abdelaal Hesham , Tonbary Ahmed El , Imqam Abdulmohsin
Published: October 2018

Gas hydrates are one of the most abundant sources of energy present today. They are formed at high pressures and low temperatures, and contain mainly water and methane. When dissociated, a large volume of water forms, much of which is produced. This research performs a simulation study on how to decrease the volume of water produced from gas hydrate reservoirs by utilizing an in-situ heating method combined with a low concentration thermodynamic inhibitor injection. Since gas hydrates form at high pressures and low temperatures, depressurizing the reservoir, or increasing its temperature would cause the solid hydrates to become unstable, and dissociate. The research begins by building a hydrate reservoir model using almost the same description of the models present in the literature in order to compare the results obtained. Several simulation runs were then performed using various production methods, several types of inhibitors, and finally testing and optimizing the newly proposed production method which combines thermal stimulation with inhibitor injection. The optimization process involves testing the novel method using 5-spot, 7-spot, and 9-spot production methods. The effect of each variable on the water recovery was studied, and the conditions under which the lowest water recovery were obtained. The highest water production occurred during glycol injection since it had the largest endurance to hydrate reformation and thus the largest water flow duration. When the glycol was combined with the thermal stimulation method however, the lowest water recovery was obtained. This is mainly due to two factors which include high rate of depletion of reservoir pressure, and the significant decrease in glycol concentration when used with thermal stimulation. This novel production method was chosen as the best method in terms of low water recovery based on a comparison of its recovery with that of all the other methods. The second task was to further optimize this method by introducing several well patterns and comparing their performance to that of the single well case. The largest number of wells, 9-spot pattern, was found to have the lowest water recovery due to the extremely high rate of reservoir pressure depletion. Gas hydrate production is still considered in its preliminary steps due to the complexity of hydrate reservoirs. By understating the mechanism by which these reservoirs can flow, and trying to reduce the excessive water production associated with these reservoirs a better understating of how to economically and safely produce from gas hydrate reservoirs is reached. This may lead to the utilization of this source of energy in the near future.
Optimization of Drawdown Pressure About the Ultra-Deep Fractured Carbonate Reservoir
Authors: Shuang-gui LI , Yu Chen
Published: October 2018

The original stress equilibrium of the formation is disturbed after borehole creation, and stress concentration is formed around the wellbore. During production, if drawdown pressure is too high, it will cause wellbore collapse and associated accidents. On the contrary, if the drawdown is too small, the production cannot meet the development needs. The ultra-deep fractured carbonate formation is tight and the in-situ stress is high. Dependent on the development of horizontal fractures and the degree of fracture filling and cementation, the distribution of UCS along the wellbore is quite different, leading to a larger variation of critical drawdown pressure. Meanwhile, different wellbore trajectories will result in different stress concertation around the wellbore and influence the critical drawdown pressure.

Furthermore, UCS of the rock will be reduced when the rock is soaked in completion fluids for a long time, and the critical drawdown pressure will be reduced. In view of these problems, this paper carried out a series of core tests, and developed a model to predict the critical drawdown pressure of uncased wellbores in fractured carbonate reservoirs. The influences of completion-fluid immersion and well trajectory on critical drawdown pressure is investigated. The results show that the critical drawdown pressure of vertical wells is less than that of horizontal wells. The critical drawdown of wellbores along the minimum horizontal principal stress is larger compared with wellbores along the direction of maximum horizontal stress. Completion-fluid immersion can cause a 4-5% reduction in critical drawdown pressure.
Advances in Non-Aqueous Drilling Fluid Formulations Through Innovative Surfactant Technology
Authors: Indulkar Sakshi , Thakur Swapnil , Asrani Megha , Singh Anil Kumar , Gupta Vivek , Patel Arvind
Published: October 2018

A number of problems such as emulsion instability, environmental issues and cost, persist in current liquid invert emulsifier technology of non-aqueous drilling fluids (NADF). These short comings are mainly due to incorporation of required components, solvents and mutual solvents in formulating emulsifier package, however they can be mitigated through innovative powdered emulsifier technology. This paper will present concept, design and chemistry of novel powdered emulsifier technology and compare their performance against current liquid emulsifiers.

New technology will include the development of solvent and mutual solvent free "solid state emulsifiers", and their applications in mitigating or eliminating the adverse effects of mutual solvents and other solvents which are incorporated in traditional liquid emulsifier technology. New technology in the form of advances made in emulsion technology, unique manufacturing technology of emulsifier additives and fluid formulations will be discussed.

NADFs have been used since their early introduction in late 1930s1, primarily because of their performance benefits when compared to water-based drilling fluids. Despite the performance advantages, NADF technology has not been without challenges because the complexity of drilling operations has grown enormously. These new challenges have required that NADFs be environmentally friendly, stable and possess desirable mud properties over broad range of temperatures and pressures, effective in broad range of applications and be cost effective. Through the constant efforts of research scientists in drilling fluid industry, advances have been made in NADF formulations, particularly in base fluids and surfactant technology to overcome or mitigate these challenges 2. However, the problems still exist. Various test we conducted for performance comparison of conventional liquid emulsifier and new technology solid state emulsifiers. After analysing the results, it was concluded that mutual solvents used in formulating liquid emulsifiers resulted in reduction of emulsion stability as much as 30%. The laboratory assessment, comparison and field applications of the newly developed powdered emulsifier technology will be highlighted. The development of this innovative powdered emulsifier technology has mitigated or resolved many issues, such as pour point, toxicity and other logistic problems to keep the NADFs at the forefront of the drilling fluid industry.

The paper will present newly developed concept and design of novel solid emulsifier technology to combat the associated challenges. These challenges include environmental issues, performance requirements, logistics and cost associated with current technology.
The Application of Fully Dissolvable Frac Plug Technique in Weiyuan Gasfield
Authors: Li Ming , Chen Lin , Wei Ran , Liao Chenglong , Fu Tao
Published: October 2018

Frac plug multistage fracturing technology is one of the main unconventional reservoir stimulation technologies. The fully dissolvable frac plug is a more efficient staged fracturing tool in compare with the fast-drilling frac plug. One of the most important advantages by using dissolvable frac plug is that the milling-out operation conducted in traditional plug is no more necessary, which significantly reduces the costs and risks of plug removal.

Weiyuan shale gas field is located in the southwest of China, most platforms have three-six horizontal wells. The blocking and sticking problems often happened due to the casing deformation or accumulation of sand in the wellbore. In this paper, the main technical challenges of fully dissolvable frac plug technology are analyzed. The field application of well A is described, including frac plug selection, field operation, the solutions under different blocking and sticking scenarios, sand flushing operation and problem analysis, etc.

The blocking and sticking problems happened in the process of tool string delivery. Then, corresponding solutions are prepared for the blocking and sticking problems before using the dissolvable plugs. Twenty-two fully dissolvable frac plugs and twenty-three fracturing balls were used in well A to complete twenty-three stages of fracturing. Field application results show that the fully dissolvable frac plug for multistage fracturing technology completes the reservoir stimulation safely and efficiently. The technology could meet the demands for pressure bearing performance and dissolving property.

This paper offers a case study that describes the application of fully dissolvable frac plug technology in long horizontal well of shale gas. It also provides an experience and reference case for engineers to develop other fracturing wells in unconventional reservoir.
A Review on Recent Developments and Progress in Natural Gas Processing and Separating Using Nanoparticles Incorporated Membranes
Authors: Amusa Abdulhameed A. , Ahmad Abdul Latif , Adewole Jimoh K.
Published: October 2018

This review paper centers on recent development and progress in natural gas processing and separation using nanoparticles incorporated membranes. Development of mixed matrix membranes (MMMs) is to enhance the performance of polymer membranes for CO2 separation. Overview of natural gas is illustrated. Abridged versions of MMMs development using an ideal polymer with corresponding nanoparticles are presented. The compatibility between nanoparticles with polymers is discussed. Finally, forecast on MMMs for future trends are highlighted.
Digital Transformation of PETRONAS' Hydrocarbon Production Allocation System (HyPAS)
Authors: Isa Edalawati Md , Salim Salmizana M , Ghani Ahmad Majdi , Karim Ili Izyan
Published: October 2018

This paper highlights the digital transformation journey of Malaysia's upstream hydrocarbon production allocation system. A standardized, web-based allocation system (herein referred as "HyPAS") was developed in place of two distinct medium used for different allocation network across Malaysia's region; namely the spreadsheet-based approach, and an age-old FORTRAN based system.
Optimization of the Annulus Nitrogen Injection Volume in Offshore Wells With Annular Pressure Buildup
Authors: Wang Hao , Zhang Hui , Li Jun , Zeng Yijin , Ding Shidong , Tao Qian
Published: October 2018

In the development and production process of offshore heavy oil thermal recovery wells, the rise of annulus fluid temperature will lead to extremely high annular pressure, which will threaten the casing safety and wellbore integrity. Nitrogen injection is often applied to release the annular pressure. However, insufficient injection can't solve the problem and too much nitrogen will lead to economic loss and poor effect. Therefore, there exists an optimal injection volume in nitrogen injection operation.

In this study, based on the thermodynamic principle and the PVT equation, the reducing mechanism of the nitrogen physical properties and injection volume for annular pressure was analyzed and a calculation method is presented. Then a well in Bohai sea of China is taken as an example to calculate the optimal injection volume and analyze the influence of nitrogen physical properties, annulus temperature and casing strength parameters on the optimal injection volume. At last, the prediction model of the optimal injection volume of annulus nitrogen and a safety evaluation method for production string under nitrogen injection are proposed and some optimization methods are given for nitrogen injection.

The results show that nitrogen injection can effectively reduce annular pressure over 40%. With the increase of nitrogen injection volume, the reduction rate of annular pressure and the injection efficiency decreases gradually. The optimal injection volume of annulus nitrogen is mainly determined by annulus temperature, intial temperature and pressure of nitrogen. Injecting nitrogen at the optimal volume can maximize the economic and safety benefit. It is necessary to control injection volume when taking nitrogen injection operation.

This work provides a prediction model for determining the optimal nitrogen injection volume to reduce annular pressure buildup, and a production string safety evaluation method was also proposed. These can provide guidance for field nitrogen injection operation.
Transient Pressure Behavior of Acid Fracturing Well in Tidal Flat Carbonate Reservoirs
Authors: Shi Wenyang , Yao Yuedong , Cheng Shiqing , Li He , Feng Naichao , Wang Yadong , Shi Zhiliang , Gao Min
Published: October 2018

Different from the marine carbonate reservoir, Tidal Flat Carbonate Reservoir (TFCR) rock contains Natural Fracture (NF) and Natural Dissolved Vugs (NDV). The NDV are usually distributed alone or along the NF in the rock core, which can be observe by the eyes. In the process of acid fracturing, Acid Fracturing Fracture (AFF) will activate NF and crack Carbonate Rock Matrix (CRM), acid fluid will etch NF and NDV. Finally, a complex Acid Fracturing Fracture Network (AFFN) with high conductivity is formed in Acid Fracturing Region (AFR). However, the range of the AFR is limited, there are still a lot of NF and NDV in Carbonate Rock Region (CRR).

The porosity and permeability of CRM are very low, the distribution pattern of NF and NDV are very complex. When pressure through the AFR and spread to the farther reservoir rock, the pressure behavior begins to show the multiscale flow characteristics. Therefore, the Non-Darcy Flow (NDF) of CRM in CRR and the Stress Sensitivity (SS) of AFFN in AFR need to be considered. Unfortunately, low porosity and low permeability in TFCR are seldom considered in typical transient pressure behavior model, such as NDF caused by Threshold Pressure Gradient (TPG) and SS caused by reservoir pressure decrease.

This paper presents a new transient pressure analytical model in TFCR, where the reservoir flow is subdivided into two flow regions: AFR and CRR. The effect of NDF in CRR and SS in AFR are both considered. Laplace transformation, perturbation method, Green function and Stehfest numerical inversion are employed to solve the model comprehensively. The model solution is verified with real transient pressure test data in TFCR. The effects of related influential parameters on transient pressure behavior, such as NDF, SS, acid fracturing area, rock property improvement degree and flow channel improvement degree.

Field example is conducted to shown the applicability of the new model, applied to the actual TFCR, the actual Bottom Hole Pressure (BHP) data of several acid fracturing wells pressure buildup test is well fitted. The results of this study can be helpful to better understand the flow mechanisms and transient pressure behavior of acid fracturing well in TFCR, which can be also used to evaluate acid fracturing measure and transient production performance. The judgement and recognition of the acid fracturing area and improvement degree have guiding significance for the repeated acidizing or hydraulic fracturing in the later stage of increasing production.
Optimizing Brown Fields Through Adherence to Proper Well Intervention Workflow
Authors: Chinweike Okeke
Published: October 2018

The sudden fall of crude oil prices starting from the end of year 2014 got many astonished, as the price of Brent crude fell from $110 per barrel to $27 per barrel early 2016. Oil and gas producing companies were coerced to reduce spending on risky and costly exploration and production projects. Without doubt, all attention will be focused on production optimization from brown fields through the use of different well intervention strategies as the only proved means to gain more by spending less. Oil price has improved, hovering around $70 to $81 per barrel, in this current period of low oil price, there is much reason to embrace different well intervention strategies to keep wells on-stream more commercially. Since brown fields account for over seventy percent of the world’s energy demands, there is the need to revitalize these brown fields. With advances in well intervention strategies, getting as much as possible from a brown field is becoming more and more feasible. Thus, this study aims to develop the best workflow to optimize production through the application of different well intervention strategies. The results from a mature field in the Niger Delta were used to analyze the improvement of production through different well interventions. Extensive analysis of production history/performance, review of petrophysical parameters, identification of some subsurface (down-hole completions/well deliverability) and surface (facilities) constraints were carried out. The field has eight reservoirs, twenty-three wells, thirty-eight strings out of which production optimization using well interventions were applied on seventeen of the strings. Eclipse dynamic simulation software, Prosper and Ecrin well-test software were used to build the necessary models and analyze different sensitivity scenarios before and after each well intervention.
Experimental Study of Effects of Water-in-Oil Emulsions Flow on Wax Deposition in Subsea Pipelines
Authors: Adeyanju Olusiji Ayoade , Oyekunle Layioye Ola
Published: October 2018

Experiments were performed to simulate the wax deposition in the flow of water in crude oil emulsions in subsea pipelines using a flow facility. Two water in crude-oil emulsions (Samples A & B) synthesize from two crude oil samples and their respective formation water from Orogbo and Okpohuru flow stations in the Southern Nigeria were used in the study. In the later period of wax deposition the combined effects of molecular diffusion and shear removal overwhelm the trapped water globules effect which dominates the wax deposition initially. The emulsions pour points increase from 30 to 41°C and the viscosities at 26 oC from 40 to 142 mPas, when the basic sediments and water of the crude samples increase from 10 to 40 °C. Addition of 250 ppm of Basorol E2032 (demulsifier) to the mixture of crude oil emulsion and 450ppm of long chain acrylate ester co-polymer (pour point depressant) was able to reduce the dimensionless wax thickness by 21.4 and 8.7% for crude oil samples A & B respectively. Addition of the demulsifier to the mixture of the emulsified oil and the pour point depressant enables the emulsified crude oil to be separated into its separate compositions of crude oil and water thereby making the stratified water-crude oil liquid flow to characterize the fluid flow in the pipeline leading to reduction in wax deposition.
The Effects of Hole Wash-Out on Wellbore Centralization and Effective Zonal Isolation in Consolidated and Unconsolidated Gas Reservoirs
Authors: Adesanya Olukayode , Mofunlewi Samuel S. , Ighodaro Osaze , Idongesit Victor , Dickson Tobin
Published: October 2018

Formation evaluation and geological characteristics of the reservoir have been key factors that help in determining the best practices in drilling and completion operations. Primary cementing in unconsolidated or consolidated gas formations presents even bigger challenges due to the volatility of gas and a high risk involved with respect to maintaining good well control across the various phases involved in delivering a well.

To achieve good zonal isolation through cement placement, it is important to ensure that best operational cementing practices are properly incorporated with a robust slurry design based on specific formation data. Beyond the reliability of these factors, it is important to have accurate hole data which inform the optimum centralizer program and volume determinations. One key factor that hinders the accuracy of this information is the extent of wash-outs in an open hole. Hole wash-outs and the level of wash-outs in a wellbore depends on various factors some of which includes, the degree of consolidation of the formation environment, the practices deployed during the drilling phase of the wellbore and the operationally-influenced delays due to challenges experienced in the drilling phase of the hole section.

Over time, the levels of wash-out experienced in a wellbore have been seen to greatly influence the centralization effectiveness, and depth accuracy with respect to annular slurry placement. This paper will be analyzing case studies from gas wells that were drilled in both consolidated and unconsolidated formations, the effect of wash outs on the centralization stand-off and how these wash-outs affect the quality of zonal isolation across these hole sections. The paper will include best practices to improve zonal isolation when dealing with wash-out intervals.
The Effect of Biochar on Residual Polyaromatic Hydrocarbon Concentrations in Bioremediation
Authors: Oriaku T. O.
Published: October 2018

In this study, the efficiency of biochar as a remediation tool in reducing the concentration of residual pollutant concentrations (polyaromatic hydrocarbons- PAHs) in coal tar remediated soils was investigated over a 30-day period. Results from laboratory microcosm experiments showed that amendment with biochar of a finer particle size ≤ 1mm resulted in a 7% reduction (although not significant, p>0.05) in the priority PAH groups (2-6 ringed compounds) for the nutrient and biodiesel-amended microcosms compared to the non-biochar experiments while a 4% decrease (p>0.5) was also observed for the biochar amended controls compared to their non-biochar category. In a stepwise treatment approach, the 2-6 ring PAHs in the biodiesel amended microcosms were reduced by 4-16% (p>0.5), while decrease was seen only for 3-5 ring compounds in the nutrient amended experiments. The biochar amended control also showed a 6-7% (p>0.5) reduction in the 4-6 ring PAHs. However, after 30 days of biochar amendment with a larger particle size >1mm, increased concentrations in PAHs was noticed. The biodiesel-amended microcosms had 48% increased levels in the total 16 USEPA PAHs compared to their non biochar amended samples, while 19% increase was observed for the nutrient amended experiments relative to their non-biochar experiments. In all of these experiments, the PAH groups (2-6 ringed) showed increased concentrations in the biochar amended samples. The observation of reductions in the PAH groups of the 16 USEPA pollutants in soil amended with finer particles of this carbonaceous material, showed the likely effect of particle size on the sequestration ability of biochar in soil amendment techniques. Increased concentrations of PAHs seen after amendment with larger particle size of biochar could be due to the possible desorption of these pollutants during the extraction procedure employed prior to measurement. Although the reductions in residual PAH concentrations recorded after biochar amendment were not statistically significant, the non-interference of biochar in the visible growth of fungal hyphae and moulds in the biodiesel treated microcosms and the observed slight reductions in the PAH groups of the 16 USEPA pollutants in the soil amended with finer particles of biochar, compared to the non-treated microcosms, showed the potential of biochar amendment in bioremediation studies. Also prolonged contact and incubation time, following biochar amendment are likely determinant factors for the effectiveness of this amendment technique.