bluuebunny/crossref_metadata_2025 huggingface dataset:
Simplified Solution for Managed Pressure Drilling - System that Drillers Can Operate
Authors: Patil Harshad , Knight Ian , Hovland Svein , Dietrich Earl , Boutalbi Said , Leal Jerib , Gonzalez Rick , Matherne Greg
Published: September 2021

Until recently many of the wells on US land that were drilled using Managed Pressure Drilling (MPD) technology utilized one size fits all equipment designed for the offshore market. Since the cost and personnel requirements needed to run the offshore manifolds became a challenge due to market conditions and Covid-19 restrictions, the drillers sought a cost effective and simpler system to conduct their day-to- day operations. The challenge was to drill long laterals in Permian and Haynesville without losing the necessary MPD functionality that proved beneficial to reduce the risks associated with safety and to enhance drilling efficiency. For the MPD control system experts, the task was to correctly identify and automate MPD system’s functionality that would be of greatest use to the drillers to sustain their drilling performance.

The concept of developing an easier to operate control system was undertaken wherein system accuracy and precision was maintained at the forefront of the development process. Electric motors/actuators and necessary drivers that could work directly on rig power were selected and tested. Control system logic that operates the chokes was modified to quickly adapt to the changes in drilling conditions, maintaining the necessary accuracy. This was done by studying and understanding drillers activities and behaviors like automated pump ramp down speed during connections, pipe movement during tripping etc. Specific MPD engineering charts, simple to decipher graphs, and necessary calculation tables were developed for the drillers to use for managing bottomhole pressures. Calculations which included specific schedules for spotting weighted pills were provided to maintain simplicity of the operations and something the drillers could easily execute.

Today, many drillers are using this MPD solution to drill long laterals (Hovland et.al 2020). This trend is slowly leading to reduction of rig MPD personnel, especially during Covid-19, while the drillers are getting familiar with and operating MPD systems. A few of the crucial items that have allowed the drillers to run MPD on their own include MPD controls connected to drilling automation systems and the subsequent continuous revision of these controls based on understanding drillers tasks and needs. The use of electric motors enabled quick adoption to the changing drilling conditions while making connections, tripping etc.

The furnished MPD calculations and graphs that drillers could follow for applying required MPD choke pressures kept MPD adaption simpler. The modifications made to the MPD choke controls geared towards facilitating necessary automation enabled the drillers to get trained in few days and operate the MPD systems while maintaining the same level of speed and performance.
Catastrophic Events and Human Error: A Few Rotten Apples or Organizational Dysfunction?
Authors: Bridle Peter
Published: September 2021

By July of 2021, it would have been 33 years since the 1988 Piper Alpha tragedy in the UK sector of the North Sea where 167 oil field workers lost their lives. Without question, the incident was a watershed event for the international oil and gas industry. And not simply because of the immediate toll in human lives lost, but also in terms of the devasting aftermath endured by countless friends, families and loved ones whose lives were forever changed on that fateful day. The tragedy also served to illustrate how much work would be needed by the oil and gas industry to fully understand and better manage those operating risks that possessed the potential for catastrophic loss in terms of business cost and reputational impact.

In the wake of the public enquiry that followed and chaired by Lord Cullen of Whitekirk, one of the principal recommendations resulting from the disaster required that the international oil and gas industry do a much better job in determining both its major hazards (i.e. major operating risks) and in creating the necessary operating conditions to demonstrate that such things were being well managed. The objective being to provide tangible assurance that the likelihood of the industry ever incurring such a calamitous event again in the future had been reduced to as low as reasonably practicable (ALARP).

In taking its responsibilities very seriously, the international oil and gas industry responded by raising the profile of the management of Health, Safety, and the Environment (HSE) across the wide spectrum of its global operations. By the mid-nineties, the industry had implemented comprehensive and structured systems of work within the framework of purposely built HSE Management Systems using templates designed and developed for the industry via the International Oil and Gas Producers (IOGP)*.
Delivering Automated Reservoir Management with Birth of the First Ever Universal Inflow Control System UICS
Authors: Killie Rune , Paterson Grant J. , Lager Thorleif
Published: September 2021

Conventional ICDs were invented for long horizontal wells to promote a more uniform inflow profile. Later, AICDs were developed, which utilize viscosity contrast between fluids to impose a larger hydraulic resistance in sections with inflow of undesired fluids, like gas and water. However, these AICD technologies cannot be used to choke back inflow of water in reservoirs where oil and water have similar viscosities, and they also tend to impose large pressure drops even for single-phase oil at high flow rates. The objective of the work presented here has therefore been to develop an inflow control technology that removes these limitations.

The resulting Density Activated Recovery (DAR™) technology utilizes difference in fluid density rather than viscosity contrast to control fluids downhole. It is a fully autonomous, binary system that is either fully open or closed, where "closed" means that it only allows a small pilot flow. More specifically, it can be considered a "dual ICD" with flow through a large port when open, and a small port when "closed". The flow capacity and choking efficiency are therefore fully defined by the diameters of these two ports. Furthermore, it can close and reopen at any pre-determined water and gas fractions, that are completely insensitive to flow rate, viscosity and Reynolds number. This makes it universally applicable to control any wellbore fluid along the entire reservoir section.

After successful prototype testing in 2018, the DAR technology has now undergone a comprehensive full-scale system-qualification program including a final flow performance test where the system was tested at 240 bar and 90ºC with saturated 0.8 cP oil. The tests demonstrated up to seven times higher flow capacity with the density-based DAR technology compared with viscosity-dependent AICD technologies. The system successfully and repeatedly closed and reopened for both gas and water. As oil and water had similar viscosities, the tests also proved how this technology can be used to stop undesired inflow of water in light-oil reservoirs.

Being insensitive to flow rate, the DAR system is also insensitive to local variations in pressure and productivity along the reservoir section, which reduces the negative consequences of geological uncertainty and allows the same design to be used at every location in the well. It can also be configured to ensure complete mud removal during well cleanup and can even stop inflow of water in gas wells, where the undesired fluid has higher viscosity than the desired fluid. More importantly, this technology can deliver automated reservoir management to a level where it influences how wells are drilled and fields are developed. Accelerated oil production and the reduced need for reinjection of gas/water will also reduce the associated greenhouse gas (GHG) emissions considerably.
Well Connectivity Analysis with Deep Learning
Authors: Li Yuanjun , Suzuki Satomi , Horne Roland
Published: September 2021

Knowledge of well connectivity in a reservoir is crucial, especially for early-stage field development and water injection management. However, traditional interference tests can often take several weeks or even longer depending on the distance between wells and the hydraulic diffusivity of the reservoir. Therefore, instead of physically shutting in production wells, we can take advantage of deep learning methods to perform virtual interference tests.

In this study, we first used the historical field data to train the deep learning model, a modified Long- and Short-term Time-series network (LSTNet). This model combines the Convolution Neural Network (CNN) to extract short-term local dependency patterns, the Recurrent Neural Network (RNN) to discover long-term patterns for time series trends, and a traditional autoregressive model to alleviate the scale insensitive problem. To address the time-lag issue in signal propagation, we employed a skip-recurrent structure that extends the existing RNN structure by connecting a current state with a previous state when the flow rate signal from an adjacent well starts to impact the observation well. In addition, we found that wells connected to the same manifold usually have similar liquid production patterns, which can lead to false causation of subsurface pressure communication. Thus we enhanced the model performance by using external feature differences to remove the surface connection in the data, thereby reducing input similarity. This enhancement can also amplify the weak signal and thus distinguish input signals. To examine the deep learning model, we used the datasets generated from Norne Field with two different geological settings: sealing and nonsealing cases. The production wells are placed at two sides of the fault to test the false-negative prediction.

With these improvements and with parameter tuning, the modified LSTNet model could successfully indicate the well connectivity for the nonsealing cases and reveal the sealing structures in the sealing cases based on the historical data. The deep learning method we employed in this work can predict well pressure without using hand-crafted features, which are usually formed based on flow patterns and geological settings. Thus, this method should be applicable to general cases and more intuitive. Furthermore, this virtual interference test with a deep learning framework can avoid production loss.
The Digital Transformation of the Knowledge Worker
Authors: Creus Fernando Luis
Published: September 2021

Technological advances unveil a dual reality in the oil and gas Industry. On one hand, the benefits of blockchain and artificial intelligence (AI), among others, has arrived to revolutionize the industry. On the other hand, industry professionals remain trapped in bureaucratic processes that undermine their performance. The diagnosis: knowledge workers, responsible for optimizing the recovery and economic performance of the fields, are the missing link in the digital transformation chain. They are suffering the digitalization of the status quo.

This paper puts forward a broad digital transformation framework designed to increase the knowledge worker's productivity. Digital transformation is not just about the implementation and use of cutting-edge technologies. It is also the response to digital trends, and about adopting new processes and redesigning existing ones to compete effectively in an increasingly digital world. Prioritizing technology as the ultimate goal puts the business processes and the knowledge workers aside from the discussion.

The key to this proposal is rethinking the business model according to the possibilities of new technologies based on a six-dimension scheme:Corporate strategy: It defines the long-term vision and investment criteria for value creation. Technology is an element within a business scheme that should not be analyzed in isolation.Digital strategy: Within the corporate strategy, what operational and strategic role does technology play? Should it only support the company's operation, or should it drive strategic reinvention?Culture: While digital transformation is the company's response to digital trends, culture is the muscle that provides (or not) the attributes required to succeed in this transformation endeavor. Innovation and creativity should be promoted as part of the company's DNA.Knowledge processes: A business model, built on new technologies, will necessarily impose new and automated practices. While the automation of physical processes is a fact, the automation of knowledge processes is the weakest link.Data governance: It defines the necessary conditions that guarantee the quality of the information and its strategic acquisition. Two elements are a must: the automation of processes, thereby avoiding arbitrariness in data management; and centralized databases, thereby eliminating data duplicity and criteria discrepancy.Data Science: At this point in the model, the company has efficient, automatic, and fast processes, assuring the quality and availability of the data from its conception to the final storage. Then, data scientists will have all the means, and a clear and aligned vision (corporate strategy) to extract meaningful insights for the business.
Issue with Stone-II Three Phase Permeability Model, and A Novel Robust Fundamentals-Based Alternative to It
Authors: Gupta Subodh
Published: September 2021

The objective of this paper is to present a fundamentals-based, consistent with observation, three-phase flow model that avoids the pitfalls of conventional models such as Stone-II or Baker's three-phase permeability models.

While investigating the myth of residual oil saturation in SAGD with comparing model generated results against field data, Gupta et al. (2020) highlighted the difficulty in matching observed residual oil saturation in steamed reservoir with Stone-II and Baker's linear models. Though the use of Stone-II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears to counter-intuitively limit the flow of oil when water is present near its irreducible saturation.

The current work begins with describing the problem with existing combinatorial methods such as Stone-II, which in turn combine the water-oil, and gas-oil relative permeability curves to yield the oil relative permeability curve in presence of water and gas. Then starting with the fundamentals of laminar flow in capillaries and with successive analogical formulations, it develops expressions that directly yield the relative permeabilities for all three phases. In this it assumes a pore size distribution approximated by functions used earlier in the literature for deriving two-phase relative permeability curves. The outlined approach by-passes the need for having combinatorial functions such as prescribed by Stone or Baker.

The model so developed is simple to use, and it avoids the unnatural phenomenon or discrepancy due to a mathematical artefact described in the context of Stone-II above. The model also explains why in the past some researchers have found relative permeability to be a function of temperature. The new model is also amenable to be determined experimentally, instead of being based on an assumed pore-size distribution. In that context it serves as a set of skeletal functions of known dependencies on various saturations, leaving constants to be determined experimentally.

The novelty of the work is in development of a three-phase relative permeability model that is based on fundamentals of flow in fine channels and which explains the observed results in the context of flow in porous media better. The significance of the work includes, aside from predicting results more in line with expectations and an explanation of temperature dependent relative permeabilities of oil, a more reliable time dependent residual oleic-phase saturation in the context of gravity-based oil recovery methods.
The Case for Combining Well Intervention Solutions to Optimize Production and Reduce Risk Exposure
Authors: Meling Eyvind Morten , Mourani Houssam , Schwanitz Brian Joseph
Published: September 2021

While optimizing hydrocarbon production, combining well intervention solutions can enable significant benefits due to reductions in risk exposure: fewer rig-ups and downs, less in-the-hole operating time and the carbon production and costs associated with rig time, especially when working from sub-sea intervention vessels. Operators in general, prefer to achieve multiple intervention objectives in a single descent in the well, if the operations complexity does not increase the risk exposure to an unacceptable level. Often, the risk of a mis-run, causing a second run, meets the cost vs value criteria for acceptable risk, when the large operating time savings of a successful combined run is considered.

In collaboration with a mechanical e-line provider, North Sea operators developed three reliable combination solutions which increased their operational efficiency. Combining these most run services under more standard, common scope of work procedures, saved the operator time in planning, execution, risk exposure and money, while enabling them to produce hydrocarbons in the saved time. This paper will present the technology involved with these combined services, use a typical example of each and the cost savings achieved.
Downhole Monitoring of Fractures in a Waterflood Development – Part II
Authors: Kohli Abhinandan , Kelder Oscar , Castelijns Ralph , Eijs Rob van , Volkov Maxim
Published: September 2021

For maintenance of the reservoir pressures and enhanced oil recovery in oil producing formations, waterflooding is often implemented by the Operators. This is achieved by drilling injection wells or converting the oil producing wells into injectors. The injection wells are located at carefully selected points in the oilfield so that the water displaces as much oil as possible to the production wells before the water starts to break through. A significant saving in an oilfield development can be obtained by reducing the actual number of injecting wells and increasing each of the injector wells’ capacity for injection. Balancing the injection and produced volumes often involves injecting at high pressures leading to the fracture of the reservoir rocks along a plane intersecting the wellbore. This happens when injection pressure exceeds the minimal principal stress and the tensile strength of the rock, thereby creating a hydraulic fracture. With continuous injection, these fractures start propagating into the reservoir and may reach the reservoir caprock, which may decrease the integrity and possibly lead to out of zone injection.

The study of evaluation of downhole fracture monitoring is divided into two parts. In the first part of the paper (Kohli, et al., 2021), a downhole verification approach to identify the fracture initiation point(s) is the focus. It describes the planning, execution and interpretation of the downhole data. This includes spectral acoustic monitoring and modelling of the temperature responses to quantify the injectivity profile.

In this second part of the paper, the direct business impact is discussed by further integration of acoustic monitoring and temperature modeling data with detailed results from of fracture dimension (height) measurement by means of pressure fall off tests. Combined, both studies form an integrated approach that the operator took to prove that the fracture network propagation remains within the reservoir and that the top seal integrity is maintained.
Through Barrier Diagnostics to Locate Multiple Barrier Failures in Complex Well Failure Scenario and to Enable Successful P&A
Authors: Volkov Maxim , Zaripova Asiya , Sikander Sultan , Ezwai Jamal , Altaeb Islam , Elbouma Osama
Published: September 2021

Objectives/Scope

A 60-year-old well exhibited a leak at the surface and sustained annuli pressure (SAP) in all three annuli - A, B and C. The age of the well coupled with the symptoms suggested a complex multi-barrier failure scenario that needed to be diagnosed quickly and accurately so that the well could be secured safely. The paper shows how the comprehensive set of downhole diagnostics, including metal and cement barriers integrity assessment, aided in planning and execution of well intervention to secure the indicated failures.

The well intervention team selected an approach to investigate the barriers status prior the rig came to the location. Surface diagnostics included evaluation of pressure trends, completion design, leak fluid composition and drilling records analysis which guided the selection of downhole survey. The input parameters for downhole through barrier diagnostics were:

Downhole through barrier diagnostics targeted the evaluation of leak paths and failures in well barriers and included:

This paper explores the concept, planning, execution and achieved results of the downhole diagnostics performed and how the results were implemented by Operator.
Accuracy and Uncertainty Evaluation of Measuring the ISO Long-Term Conductivity of Proppants
Authors: Vysotskiy Roman , Makashova Galina , Radaev Vladimir , Yudin Alexey
Published: September 2021

One of the critical factors in planning a hydraulic fracturing treatment is proppant selection. Conductivity is an important property for ensuring efficient reservoir stimulation. Conductivity data obtained during laboratory measurements help determine which proppant to use. ISO provides standard testing procedures and methodology for measuring the long-term conductivity of proppants but does not document expected measuring uncertainty. This paper addresses accuracy and uncertainty estimation of ISO 13503-5 conductivity measurements.

For the purposes of this study, three proppant samples were used. Two identical samples of high-strength ceramic proppant (HSP) and one sample of natural silica sand were distributed among six laboratories that participated in this study. The resulting data from measuring conductivity and permeability of the samples were used to calculate repeatability and reproducibility in terms of standard deviations in accordance with ISO 5725-2. Uncertainty of measuring the ISO long-term conductivity of proppants was calculated in accordance with ISO 21748.

The evaluation shows that conductivity and permeability values of ceramic proppant and natural sand measured by the ISO 13503-5 method have quite high interlaboratory uncertainty. Uncertainty of conductivity is from 19 to 100% depending on closure stress for values of conductivity from 3000 to 200 md-ft respectively. Uncertainty of long-term conductivity measurements increases dramatically while conductivity decreases. At the same time, internal evaluation of uncertainty in measuring conductivity within one laboratory resulted in approximately 15% as reference value of uncertainty for a single laboratory and never exceeded 30% in given conductivity range.

ISO 13503-5 prescribes testing procedures; however, it does not provide information about measurement uncertainty. This information is essential for comparing different proppants to enable reasonable selection criteria for a job, to identify proppant property inconsistency and quality decline over time due to changes in production process or raw material, or to resolve discrepancies in different laboratory measurements. Uncertainty values were estimated for a wide range of conductivity data and different proppant types.
Model-Free Assessment of Inter-Well Connectivity in CO2 WAG Projects Using Statistical Recurrent Unit Models
Authors: Chen Hongquan , Sen Deepthi , Datta-Gupta Akhil , Nagao Masahiro
Published: September 2021

Routine well-wise injection and production measurements contain significant information on subsurface structure and properties. Data-driven technology that interprets surface data into subsurface structure or properties can assist operators in making informed decisions by providing a better understanding of field assets. Our machine-learning framework is built on the statistical recurrent unit (SRU) model and interprets well-based injection/production data into inter-well connectivity without relying on a geologic model. We test it on synthetic and field-scale CO2 EOR projects utilizing the water-alternating-gas (WAG) process.

SRU is a special type of recurrent neural network (RNN) that allows for better characterization of temporal trends, by learning various statistics of the input at different time scales. In our application, the complete states (injection rate, pressure and cumulative injection) at injectors and pressure states at producers are fed to SRU as the input and the phase rates at producers are treated as the output. Once the SRU is trained and validated, it is then used to assess the connectivity of each injector to any producer using permutation variable importance method, wherein inputs corresponding to an injector are shuffled and the increase in prediction error at a given producer is recorded as the importance (connectivity metric) of the injector to the producer. This method is tested in both synthetic and field-scale cases.

The validation of the proposed data-driven inter-well connectivity assessment is performed using synthetic data from simulation models where inter-well connectivity can be easily measured using the streamline-based flux allocation. The SRU model is shown to offer excellent prediction performance on the synthetic case. Despite significant measurement noise and frequent well shut-ins imposed in the field-scale case, the SRU model offers good prediction accuracy, the overall relative error of the phase production rates at most producers ranges from 10% to 30%. It is shown that the dominant connections identified by the data-driven method and streamline method are in close agreement. This significantly improves confidence in our data-driven procedure.

The novelty of this work is that it is purely data-driven method and can directly interpret routine surface measurements to intuitive subsurface knowledge. Furthermore, the streamline-based validation procedure provides physics-based backing to the results obtained from data analytics. The study results in a reliable and efficient data analytics framework that is well-suited for large field applications.
An Extended Viscoelastic Model for Predicting Polymer Apparent Viscosity at Different Shear Rates
Authors: Zeynalli Mursal , W. Al-Shalabi Emad , AlAmeri Waleed
Published: September 2021

Polymer flooding is one of the most commonly used chemical EOR methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media.

The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscosity model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Furthermore, the fitting parameters used in the model were correlated to rock and polymer properties, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Moreover, the extended viscoelastic model was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It was found that implementing the viscosity model in MRST might be more accurate and practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator revealed that the latter model could yield more reliable oil recovery predictions since it accommodates the mechanical degradation of polymers. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature.
Utilizing Novel Expandable Steel Packers to Overcome Multi-Stage Fracturing Completion Deployment Challenges in Horizontal Gas Wells
Authors: Ombe Ebikebena M. , Gomez Ernesto G. , Syamsudhuha Aldia , AlKwiter Abdullah M.
Published: September 2021

This paper discusses the successful deployment of Multi-stage Fracturing (MSF) completions, composed of novel expandable steel packers, in high pressure, high temperature (HP/HT) horizontal gas wells. The 5-7/8" horizontal sections of these wells were drilled in high pressure, high temperature gas bearing formations. There were also washed-outs & high "dog-legs" along their wellbores, due to constant geo-steering required to keep the laterals within the hydrocarbon bearing zones. These factors introduced challenges to deploying the conventional MSF completion in these laterals. Due to the delicate nature of their packer elastomers and their susceptibility to degradation at high temperature, these conventional MSF completions could not be run in such hostile down-hole conditions without the risk of damage or getting stuck off-bottom.

This paper describes the deployment of a novel expandable steel packer MSF completion in these tough down-hole conditions. These expandable steel packers could overcome the challenges mentioned above due to the following unique features:

High temperature durability.

Enhanced ruggedness which gave them the ability to be rotated & reciprocated during without risk of damage. Reduced packer outer diameter (OD) of 5.500" as compared to the 5.625" OD of conventional elastomer MSF packers. Enhanced flexibility which enabled them to be deployed in wellbores with high dog-leg severity (DLS).

With the ability to rotate & reciprocate them while running-in-hole (RIH), coupled with their higher annular clearance & tolerance of high temperature, the expandable steel packers were key to overcoming the risk of damaging or getting stuck with the MSF completion while RIH. Also, due to the higher setting pressure of the expandable steel packers when compared to conventional elastomer packers, there was a reduced risk of prematurely setting the packers if high circulating pressure were encountered during deployment. Another notable advantage of these expandable packers is that they provided an optimization opportunity to reduce the number of packers required in the MSF completion. In a conventional MSF completion, two elastomer packers are usually required to ensure optimum zonal isolation between each MSF stage. However, due to their superior sealing capability, only one expandable steel packer is required to ensure good inter-stage isolation. This greatly reduces the number of packers required in the MSF completion, thereby reducing its stiffness & ultimately reducing the probability of getting stuck while RIH.

The results of using these expandable steel packers is the successful deployment of the MSF completions in these harsh down-hole conditions, elimination of non-productive time associated with stuck or damaged MSF completion as well as the safe & cost-effective completion in these critical horizontal gas wells.
Intelligent Approach for GOSP Oil Recovery Enhancement
Authors: AlDogail Ala , Gajbhiye Rahul , AlNaser Mustafa , AlNajim Abdullatif
Published: September 2021

This study aims to propose an intelligent operational advisory solution that guides the plant operation team to optimal HPPT/LPPT pressure settings that compensate for the variation in ambient temperature effect to maximize plant revenue. Traditional industry practice is to operate a gas-oil-separation-plant (GOSP) at fixed operating conditions ignoring the variation in the ambient temperature (Ta) leading to a loss in oil recovery and associated revenue. The variation of ambient temperature (Ta) highly affects the separation process, where ambient temperature varies greatly from summer to winter.

To develop a correlation, a GOSP model was constructed by OmegaLand dynamic simulator using a typical Saudi Aramco GOSP design. Oil recovery values were determined by running the process simulation for a typical range of high-pressure production trap (HPPT), low-pressure production trap (LPPT), and ambient temperature (Ta). Then, an intelligent approach was built to determine the optimum pressure of LPPT and HPPT units for each ambient temperature condition using an artificial intelligence technique.

Results show that liquid recovery decreases with an increase in ambient temperature at constant HPPT and LPPT pressures, indicating adjustment in HPPT or LPPT pressure responding to the temperature variations can improve the oil recovery. At constant LPPT pressure and ambient temperature, the oil recovery increases with an increase in HPPT pressure until it reaches the optimum value and then decreases with further increase in the HPPTpressure suggesting that there is an optimum HPPT pressure at which oil recovery is maximum. At fixed ambient temperature and fixed HPPT pressure, liquid recovery increases with increasing LPPT pressure until it reaches the optimum value, and then it decreases with further increase in the LPPT pressure suggesting that there is an optimum LPPT pressure at which oil recovery is maximum.
Integrating Sustainability into Material Management Practices
Authors: Maggioni Bruno , Giliberti Francesca , Panunzio Emanuele
Published: September 2021

Modern Society followed, and it is still largely following, a linear process for natural resources utilization: raw material extraction, goods manufacturing, use/consumption, waste generation. Such a model is proven to be not sustainable because it cannot go forever considering the limited quantity of available resources on Earth but also because of waste and process by-product management.

A multitude of diverse initiatives to change this process started at different levels and within several industries in the last years including the O&G sector. Most of these initiatives share the same principle of "regeneration": waste and materials represent, in this view, the "feedback loop" able to make the production process a circular process, instead of an open-end one.

Eni promotes and supports different initiatives to implement the principles of a Circular Economy and the objective of this paper is to describe a process implemented within Eni aimed at reducing the footprint of the Oil and Gas Industry with reference to material usage. Surplus and damaged materials are no more treated as waste, but they are re-engineered or re-conditioned (if necessary) in order to be redeployed to other projects within Eni affiliates all around the world. Nowadays this process is well structured and formalized within Eni and it is extensively applied involving all worldwide affiliates, reducing the overall CO2 footprint.

Results achieved within Eni, in the last few years, averages between 6,500 and 17,500 ton of steel of material redeployed among Eni's affiliates for a value ranging between 26 and 71 million USD. The overall average result is 23,000 CO2 equivalent ton not released per year and 242,000 GJ of energy saved (ref. to steel manufacturing estimated impact:1.9 ton di CO2/ton steel cast and 20 GJ/ton steel cast).

Extending this process to involve material and equipment manufacturers, it is possible to improve the whole supply process reducing at the "source" the material storage needs, the material surplus and the produced wastes, including the CO2 emission produced in the transport phase. Initiatives like "Just in Time" delivery and material "Buy Back", mainly applied in Countries where Framework Agreements are already in place between Eni and its manufacturers and where manufacturers have their production sites and other facilities, are essential to achieve this target. Eventually, applying the approach to the whole supply chain and operations management will allow to reduce the "last mile" warehousing and transportation needs, including the dimension and capability of the operations fleet.
Breaking Through the Boundary: Are HVFR and Landing Target The Solution? A Charlie Lake Exploitation Strategy
Authors: Mombourquette Cole , Erickson Dave , Geldreich Tim , Ross Mark , Hudson Eric , Cammaert Dan
Published: September 2021

The objective of this exploitation strategy was to evaluate fracture-driven interactions (FDI) between intervals within the Braeburn members of the Lower Charlie Lake formation. With the primary goal to determine if a single well can be drilled in the Middle Braeburn and effectively drain reserves from two previously distinct producing intervals. The target intervals in this study were separated by a boundary layer composed of interbedded anhydrite, siltstone, and dolomite layers.

Wells were completed in sequence using cemented ball-drop fracturing, and high-viscosity friction reducer (HVFR) fluid systems. Diagnostics including pressure monitoring, fracture modelling, and tracers were employed to evaluate stimulation response between wells. Realtime downhole pressure monitors observed the non-producing upper wellbore, while the lower well produced. Fluid rheology determined viscosity changes for different HVFR loadings, and fracture modelling assessed the impact of anhydrite on fracture height at different fluid viscosities. Proppant tracers injected in the lower well were logged in both wellbores observing propped communication between layers. Fluid and pressure diagnostics were used to monitor effective drainage between wells over time.

During completion of the lower well, two (2) notable pressure communication events were observed in the offsetting upper well. Following the logging applications performed on both wellbores the results displayed three (3) localized points along the offsetting lateral. At which, a propped communication event was observed within a one (1) meter radius of investigation from the offsetting wellbore. The heel-most propped communication event in the offsetting wellbore was correlated to one of two (2) observed pressure communication events. The two (2) other instances of propped communication did not correspond with an observed pressure event. Following the logging application, the lower well was flowed back and put onto production. During this production period, the upper well remained shut in. Subsequent fluid diagnostic responses have indicated an increasing FDI response, facilitating the flow of hydrocarbon from the upper to the lower wellbore. This communication was primarily observed near the heel of both wellbores. Based on the results of the diagnostic tracers, the fracture model was updated to provide a development tool that would be more predictive for fracture height growth around thin anhydrites in the Charlie Lake formation.

The technique of fracture stimulation through the anhydrite layer can be used to reduce the total number of wells required to effectively drain the formation.
Rock Heterogeneity Effects on Fluid Diversion During Stimulation Treatment
Authors: Sibarani Tiurma Theresa , Ziauddin Murtaza
Published: September 2021

Rock heterogeneities, such as variations in pore distribution, pore throat diameter, and initial permeability, significantly affect the outcome of carbonate matrix stimulation treatments. A better understanding of the influence of these parameters on stimulation and diversion, especially for the performance of self-diverting acids, is needed for efficient stimulation designs.

Carbonate rock samples from six outcrop formations, with permeability ranging from 2 to 150 md, were used in the study. Large blocks were acquired for each outcrop, and several 1.5×6-in. core plugs were drilled from these blocks. Pore structure in each outcrop was characterized by high-pressure mercury injection (HPMI) porosimetry and flowing fraction measured with nondestructive tracer tests. Pore volume to breakthrough (PVbt) for a viscoelastic self-diverting (VES) acid was determined at 150°F for injection rates ranging from 1 to 10 cm3/min. The diversion ability for the VES acid was evaluated by (1) the increase in pressure during VES acid injection and (2) the pore volumes this higher pressure was maintained.

The results show that flowing fractions measured by injection of either KCl (potassium chloride) tracer in deionized water or a dilute polymer solution is an effective means for characterizing the pore structure and for predicting the pore volume to breakthrough and diversion performance of VES acids. High-permeability grainstones such as Indiana Limestone, where most of the rock porosity is accessible to aqueous fluids (high flowing fraction), have the largest pore volume to breakthrough and the largest relative pressure buildup during injection of VES acids. Low-permeability rocks with heterogeneous porosity (low flowing fraction) have lower pore volume to breakthrough and had a relatively low-pressure build-up. The results are summarized in a master-curve, which facilitates prediction of pore volume to breakthrough of VES acids from rock properties that can be measured by non-destructive techniques. Correlations for PVbt and the diversion ability of the VES acid are presented, so that the performance of these acid systems can be estimated for formation rocks where direct measuremets of PVbt or diversion are not be practical.
Value of DTS in Multi-Stacked Reservoirs to Better Understand Injectivity and Water Flood Effectiveness – A Field Example from the UAE
Authors: Gomes Jorge , Mason Jane , Edmonstone Graham
Published: September 2021

This paper highlights the application of downhole fiber optic (FO) distributed temperature sensing (DTS) measurements for well and reservoir management applications: 1) Wellbore water injectivity profiling. 2) Mapping of injection water movement in an underlying reservoir.

The U.A.E. field in question is an elongated anticline containing several stacked carbonate oil bearing reservoirs (Figure 1). Reservoir A, where two DTS monitored, peripheral horizontal water injectors (Y-1 and Y-2) were drilled, is less developed and tighter than the immediately underlying, more prolific Reservoir B with 40 years of oil production and water injection history.

Reservoirs A and B are of Lower Cretaceous age, limestone fabrics made up of several 4th order cycles, subdivided by several thin intra dense, 2-5 ft thick stylolitic intervals within the reservoir zones. Between Reservoir A and Reservoir B there is a dense limestone interval (30-50 ft), referred as dense layer in the Figure 1 well sections.
Acid Fracturing Experience In Naturally Fractured – Heavy Oil Reservoir, Bati Raman Field
Authors: Gozel Mustafa Erkin , Uysal Serkan , Ayan Cosan , Yuce Ugur , Ozturk Egemen , Gune Huseyin Kerem , Yilmaz Ismail Sahin , Oymael Mustafa , Eswein Edmund
Published: September 2021

Bati Raman field, with an original oil in place of 1.85 billion barrels, is a naturally fractured carbonate reservoir containing 9-13 °API extra heavy oil with viscosities varying from 300 to 600 cp. Not only a wide range of pilot EOR schemes including gas, thermal and chemical methods, but also novel IOR applications have been tried in the field. CO2 injection was a game changer for this reservoir which has been the main drive mechanism since 1987. Since then, various techniques are applied to further improve the production performance of the field. This study focuses on the design and outcome of the pilot acid fracturing treatments in selected three wells in the tighter and less fractured southeastern part of the reservoir.

State of the art planning included full evaluation of well integrity, cement bond and open hole logs, geomechanics studies augmented with rock mechanics laboratory tests. Laboratory tests were also conducted focusing on sludge/emulsion forming tendencies and acid reaction rates. Using these results, expected fracture dimensions were predicted along with production forecasts. In all wells, pre-frac calibration tests were conducted to assess stress conditions and fracturing parameter optimization. The treatments were then executed, improving the procedure between each well for acid fracturing. Injections schemes were operationally efficient and various diversion techniques were used to mitigate the presence of naturally fractured zones. Pre and post-job temperature logs helped to evaluate each treatment.

The results from the wells were very positive; total production rate increased about fivefold, observed within one month after the treatments. No considerable change in water or CO2 production in the wells was observed which had been one of the most important objectives during the candidate selection process. One well was suspended, which turned out to be one of the producers of the field after acid fracturing treatment. Each well had a different post-frac production performance because of its geological characteristics and flow dynamics, making the study more valuable for better understanding of the process. The wells are still on critical observation to assess the nature of the created fractures and their longevity in the long run. Even after twelve to fifteen months of production, which is the breaking point period for fracture closure, the overall production level of the wells was double compared to pre-frac rates. One well still has a fracture dominated production while other two changed back into its pre-frac rates. Based on these results, acid fracturing campaign was extended in the area which is currently under evaluation.
Does Miscibility Alone Predict the Success of WAG Projects? Key Issues in Miscible HC-WAG Injection
Authors: Alklih Mohamad Yousef , Aljneibi Nidhal Mohamed , Khan Karem Alejandra , Dilsiz Melike
Published: September 2021

Miscible HC-WAG injection is a globally implemented EOR method and seems robust in so many cases. Some of the largest HC-WAG projects are found in major carbonate oil reservoirs in the Middle-East, with miscibility being the first measure to expect the success of a HC-WAG injection. Yet, several miscible injection projects reported disappointing outcomes and challenging implementation that reduces the economic attractiveness of the miscible processes. To date, there are still some arguments on the interpretation of laboratory and field data and predictive modeling.

For a miscible flood, to be an efficient process for a given reservoir, several conditions must be satisfied; given that the incremental oil recovery is largely dependent on reservoir properties and fluid characteristic. Experiences gained from a miscible rich HC-WAG project in Abu Dhabi, implemented since 2006, indicate that an incremental recovery of 10% of the original oil in place can be achieved, compared to water flooding. However, experiences also show that several complexities are being faced, including but not limited to, issues of water injectivity in the mixed wettability nature of the reservoir, achieving miscibility conditions full field, maintaining VRR and corresponding flow behavior, suitability of monitoring strategy, UTC optimization efforts by gas curtailment and most importantly challenges of modeling the miscibility behavior across the reservoir.

A number of mitigation plans and actions are put in place to chase the positive impacts of enhanced oil recovery by HC-WAG injection. If gas injection is controlled for gravity and dissolution along with proper understanding on the limitations of WAG, then miscible flood will lead to excellent results in the field. The low frequency of certain reservoir monitoring activities, hence less available data for assessment and modeling, can severely bound the benefits of HC-WAG and make it more difficult to justify the injection of gas, particularly in those days when domestic gas market arises.

This work aims to discuss the lessons learned from the ongoing development of HC-WAG and attempts to comprehend miscible flood assessment methods.