bluuebunny/crossref_metadata_2025 huggingface dataset:
Scale Removal with Ultrasonic Waves
Authors: Kunanz Hartwig , Wölfel Sylvia
Published: February 2021

Today, ultrasound is a widely used technology for a number of industrial applications, from processing liquids and slurries, cleaning of optical lenses and jewellery, purification of water, enhancement of mechanical and physical properties of metals, welding, dispersing, humidifiers, to material testing. In the oil and gas industry the ultrasonic technology is typically used for measurement applications. This paper describes first test and research results using ultrasonic waves to remove scaling in the borehole. So far most standard scaling treatments involve the use of chemicals. With ultrasonic treatment, it may be possible to reduce or even substitute the chemical applications. This transgression from a chemical to a physical cleaning process would most likely save costs and reduce the environmental impact. Scaling from calcium carbonate, gypsum/anhydrite or barium/strontium sulfate is considered a major issue with oil and gas production, causing the industry enormous efforts on prevention and removal. To assess the usability of ultrasound for scaling removal, a series of laboratory experiments were conducted, starting with gypsum due to its easy handling and continuing with the more critical calcium carbonate scaling. The cleaning effects could be proven and the main factors influencing the ultrasonic cleaning efficiency could be identified in the laboratory. This paper will present and discuss the findings so far and will give an outlook on future research issues with ultrasonic scale removal.
Prediction of Barite Scaling Risk and Inhibition for Oil and Gas Production at High Temperature
Authors: Zhang Fangfu , Bhandari Narayan , Kan Amy T. , Tomson Mason B. , Yan Chao
Published: February 2021

Barite (BaSO4) is one of the common scales in oil and gas production. Extensive work has been conducted to study barite nucleation and inhibition at temperatures below 100 °C. However, with the advance in deepwater exploration and production which can encounter high temperature conditions, a better understanding of barite scaling risk at high temperature (e.g., >150 °C) becomes essential. In this paper, a systematic study was conducted to explore barite nucleation kinetics from 70-200 °C in synthetic brines containing phosphonate (0-10 ppm) or polymeric (5-10 ppm) scale inhibitors. A 2-hour protection time with or without any detectable barite nucleation was employed to define the scaling risk. To detect barite nucleation, two novel apparatus were developed, a modified dynamic flow loop and a batch reactor. The modified dynamic flow loop has a retention time of up to 4 hours and is ideal to carry out experiments at above 100 °C. Ba concentrations in the effluents were monitored to determine barite nucleation more precisely compared to traditional “tube blocking” technique. The new batch reactor employs our newly developed laser detection method, a transparent pressure tube, and an oil bath. The transparent pressure tube allows laser to pass through and can withstand 150 psi pressure at 150 °C, which therefore provides an efficient and convenient approach to study the precipitation kinetics of scales and evaluate inhibition efficiency of inhibitors at high temperature. Constant inhibitor concentration isoplethes of diethylenetriamine pentamethylene phosphonic acid (DTPMP) for barite inhibition were constructed based on our experimental data. The results of this study can facilitate the selection of an appropriate DTPMP concentration for scale treatment for high-temperature oil and gas production.
Attachment/Release of Phosphonate to/from a CaCO3 Surface in Supersaturated Brines
Authors: Zhang Nan , Kan Amy T. , Tomson Mason B.
Published: February 2021

One of the most intractable concerns when engineers try to reuse the produced water as frac fluid in the Bakken and some other shale plays is the scale formation caused by the incompatibility of produced water with additives in the frac fluids and with the formation. In order to obtain a more efficient scale treatment for a successful hydraulic fracing that handles the extraordinary amount of water with high supersaturation level, the better understanding of inhibitor retention and release in the production system is urgent.

To explore the mechanism of attachment/release of phosphonate to/from a mineral surface, calcite supersaturated feed solutions with different diethylenetriamine penta (DTPMP) concentrations were introduced into the steel tubing that was internally pre-coated with a thin layer of CaCO3. It is unveiled that DTPMP attachment was dominated by the precipitation of calcium phosphonate solid once the solution is supersaturated with Ca3H4DTPMP (pKsp=53.5), and the total amount of DTPMP attached on the calcite surface added up with the increasing supersaturation of Ca3H4DTPMP. The co-precipitation of CaCO3 and Ca3H4DTPMP has facilitated the attachment of the inhibitor with the increase of supersaturation of CaCO3. The retained phosphonate was released from the surface with a steady and low level inhibitor concentration over extended period of time. Combining with the kinetics of calcium carbonate precipitation in the presence of inhibitor, a 1500 gram of calcium phosphonate precipitation can protect the scaling for about 100 days (100 bbl/day) when the saturation index of calcium carbonate (SIcalcite) is as high as 1.3.

The results provide a better understanding of calcium-phosphonate-carbonate interaction, and show the phosphonate inhibitor can continuously accumulate on the carbonate and slowly dissolve. We anticipate this study can shed a light on how much inhibitor can be delivered to the unconventional reservoir as well as the theoretical limitation of inhibitor return in the flowback water.
Scale Inhibitor Residual Analysis: Twenty-first Century Approach
Authors: Zhang Y. , Daniels J.K. , Hardy-Fidoe J. , Durnell C. , Broussard M. E. , Hammond E. , Huang X.
Published: February 2021

Control of inorganic scale deposition within the near well bore area under both natural depletion and injection water support has been a challenge to the oil industry for a number of decades. The application of scale inhibitor squeeze treatments to production wells to control the onset of inorganic scale within the near-wellbore and production tubing has been a common practice within the onshore and offshore oil and gas industry for over 30 years.

The development of subsea fields require scale inhibitor squeeze treatments with extended squeeze lifetimes while limited number of flowlines to the host facility has increased the difficulty in obtaining and evaluating individual well water samples from which residual scale inhibitor concentrations are derived. Traditional analytical techniques, while robust and widely accepted, do not provide differentiation between scale inhibitors that belong to the same chemical family (i.e.: two or more phosphonates or two or more polymers).

The individual analysis of phosphonate scale inhibitors in co-mingled flow backs from subsea wells is a particularly challenging application for analytical techniques in the industry. Advances in separation and mass detection techniques, however, provide new options to accurately measure the concentration of scale inhibitors in these fluids to very low detection limits.

This paper will describe the analytical development of these new techniques and discuss its implication to the optimization of scale squeeze treatments in subsea, deepwater developments.
Laboratory Methods for Scale Inhibitor Selection for HP/HT Fields
Authors: Daniels J. K. , Littlehales I. , Lau L. , Linares-Samaniego S.
Published: February 2021

HPHT (high pressure, high temperature) conditions create challenges and push the limits of existing technology (i.e., scale prediction modeling, testing methodology and instrumentation) and commercial scale inhibitor chemistry. Scale prediction modeling often fails at HPHT conditions and laboratory testing under appropriate field conditions have to be compromised due to instrument limitations. This paper details work done under high temperature (204°C) and elevated pressure (3,000 psi) conditions in in order to obtain effective scale control.

More specifically, this paper will discuss selection methods for continuous and squeeze scale inhibitor application via dynamic performance testing and coreflood studies for scale control in this deep-water oil production field. The technical challenges encountered such as matching the scale type predicted in the prediction software to the scale observed during dynamic tube blocking will be outlined. Thermal ageing procedures/performance testing for continual injection chemicals and performance testing of coreflood effluent from HT coreflood studies will be outlined.
Do We Need Higher Dose Scale Inhibitors to Inhibit Scale under Turbulent Conditions? Insight into Mechanisms and New Test Methodology
Authors: Chen Tao , Chen Ping , Montgomerie Harry , Hagen Thomas , Benvie Ronald , Guo Qi , Anyanwu Uche , Xu Bo , Yang Xu
Published: February 2021

Turbulent flow, especially around chokes, downhole safety valves and inflow control devices, favors scale deposition potentially leading to severe loss of production. Recently, scale formation under turbulent conditions has been studied and progressed, focused on the bulk precipitation (SPE164070) and a small bore valve loop test (SPE 155428). However, bulk precipitation is not fully representative the surface deposition in the fields and the Reynolds number of modified loop is unknown. The relationship between a measured Reynolds number and surface deposition up until this study has not been addressed.

A newly developed test methodology with rotating cylinder has been applied to generate high shear rate and evaluate surface deposition with Reynolds numbers up to ~41000. The relationship between Reynolds number and surface deposition is addressed. Using this highly representable test method for BaSO4 scale deposition, several different generic types of inhibitor chemistries, including polymers and phosphonates, were assessed under different levels of turbulence to evaluate their performance on surface deposition.

The results showed it is not always true that higher turbulence results in higher dose of inhibitor being required to control scale. It is inhibitor chemistry and mechanisms dependent. The scale inhibitorscan be classified as three types when evaluating the trend of mass deposition versus Reynolds number and the morphology of the crystals deposited on the metal surface.

➢ Type 1: Crytal growth inhibitors. The mass of surface deposition increases with the increase of turbulence, along with smaller crystals. ➢ Type 2: Dispersion and crystal growth inhibitor. The higher the turbulence, the less mass deposition, along with smaller crystals. ➢ Type 3: Dispersion scale inhibitors. The higher the turbulence, the less mass deposition. The size of the crystals has no major change.

This paper gives a comprehensive study of the effect of flow condition on the scale surface deposition and inhibition mechanisms. In addition, it details how this methodology and new environmentally acceptable inhibitor chemistry can be coupled to develop a chemical technology toolbox that also includes techniques for advanced scale inhibitor analysis and improved scale inhibitor retention, to design optimum scale squeeze packages for the harsh scaling conditions associated with turbulent flow conditions.
Minimizing Scale Deposition Through Surface Enhancement in Downhole Tools
Authors: Graham G. M. , Goodwin N. , Albino E. , Guan H , Pinto H. L. , Bezzera M. C.
Published: February 2021

The intervention of sophisticated downhole tools, such as inflow control devices (ICDs) and inflow control valves (ICVs), has led to increased shear stresses being experienced in the wellbores near these devices. This results in an increased risk of scale formation and adherence even under mild levels of oversaturation - i.e. scale is likely to form as a result of the increased shear conditions. This can lead to situations where mildly oversaturated downhole carbonate scaling regimes result in scaling when they would otherwise remain “meta-stable” and not precipitate until further up the production system where they can be easily managed. Materials of construction and surface conditions can potentially have a critical impact on whether downhole scaling and productivity impairment is observed.

In this work, we have focussed on downhole carbonate scaling under new deepwater field conditions where the drawdown in the near wellbore area results in oversaturated brine systems. Downhole conditions have been modelled and closely simulated in the laboratory to ensure that test conditions match the mild level of oversaturation expected.

The work initially examines the relationship between increased shear and increased scaling examining bulk scaling (homogeneous precipitation) and the relationship between shear and surface scaling, showing that increased scaling can be expected at higher shear. More significantly the work progresses to examine several different materials commonly used in ICVs including different metallurgies, and surface finishes as well as selected coatings. Work at elevated shear conditions clearly shows the potential to minimise surface scaling by careful material selection and/or by the use of appropriately selected coatings.

In addition to tests designed to examine the affect of shear under conventional conditions (e.g. bulk tests and high shear rotating coupon tests), a pilot rig incorporating a mock-up valve has been designed and commissioned, allowing testing of the potential for scaling under realistic downhole flow conditions at representative temperatures and pressures and at test flow rates of up to 8 l/minute. Complementary results from these tests will also be presented in the paper to further illustrate the importance of surface conditioning in critical locations.
Qualification of Chemicals/Chemical Injection Systems for Downhole Continuous Chemical Injection
Authors: Stewart-Liddon Christine , Goodwin Neil J , Graham Gordon M , Tjomsland Tore , Hustad Britt Marie , Svela Odd Geir , Olsen John Helge , Østgaard Simon
Published: February 2021

Downhole Continuous Injection (DHCI) Systems are increasingly being installed in wells for the delivery of a range of chemicals, including application-specific formulations and multi-component chemicals. Although costly, these systems offer the advantage of controlling chemical doses, preventing interruptions to production by providing constant delivery of chemicals and can be used in place of squeeze treatments that can be costly or inappropriate if formation damage is a risk.

However, such systems are not without challenges for engineering design, operation and the effective qualification required for the chemicals before use. DHCI involves chemical injection through multi-kilometre capillary tubing, as well as injection through inline filters and one or more injection valves. Failures of continuous injection systems have been linked to a variety of causes such as corrosion, particulate formation or chemical gunking, resulting in line plugging or blockage of injection valves and filters. The work described in this paper was initiated to investigate known DHCI issues within Statoil fields and to develop laboratory tests to identify characteristics of chemical formulations that result in similar behaviour, and thus allow such formulations to be de-selected prior to use.

The paper describes a range of chemical qualification methods for DHCI systems, focusing on qualifying the chemical for use in a DHCI. Test methods have been developed which demonstrate the ways in which changes in physical properties can readily occur under downhole injection which can have a considerable detrimental impact on the integrity and effectiveness of the DHCI system. These methods have now been finalised into a set of chemical qualification protocols for Statoil.

This paper will present the basis of these test protocols and thereby intends to present best practice for chemical/system qualification for DHCI. Results from both extensive laboratory method development studies and field case histories will be included throughout the paper to illustrate the challenges faced and the qualification solutions developed.
Qualification of Downhole Valves Used in Continuous Injection Systems
Authors: Stewart-Liddon Christine , Goodwin Neil J , Graham Gordon M , Tjomsland Tore , Hustad Britt Marie , Svela Odd Geir , Olsen John Helge , Østgaard Simon
Published: February 2021

Downhole Continuous Chemical Injection (DCI) systems, including both Downhole Continuous Injection systems (DHCI) and Gas Lift Chemical injection (GLI) are increasingly being installed in new wells for the application of a range of chemicals. These systems have one or more check valves at the point of injection to control the chemical flow into the wellbore and prevent wellbore fluids from entering the injection lines. In-line filters are included to remove particulates that may prevent the check valves from sealing.

The performance of the injection valves is key to the success of continual injection systems. Valve failure would lead to uncontrolled injection into the wellbore, forming low pressure gas pockets within the injection lines which can lead to changes in the physical properties of the chemical causing issues such as corrosion or gunking. In addition, if the hydrostatic pressure within the injection line drops below wellbore pressure, then wellbore fluids can start to enter the capillary tubing.

Currently, the qualification of valves is conducted using either fresh water or nitrogen. In conjunction with considerable developments made in qualification of chemicals for DHCI and GLI which were introduced in previous papers1, 2, work has been undertaken to improve the qualification of the injection system itself. This means that in addition to showing compatibility and good performance, the chemical must be suitable for the application system, and the equipment suitable for the chemical selected. Results demonstrate how different valve/chemical combinations can perform well during fluid injection but fail to hold pressure within the injection line when the flow is stopped.

The paper will present results from an extensive series of valve tests conducted in a newly designed and commissioned rig capable of operating at full reservoir temperatures (up to 200 °C) and elevated line pressures (up to 5,000 psi). The results from this work are expected to form the basis of a new range of system qualification protocols to be proposed for Statoil DHCI systems.
An Advanced Method for Preparing Ferrous Sulfide and Testing Potential Inhibitors
Authors: Fowles Robert G. , Levey Simon J.M. , Smith Clayton S.
Published: February 2021

Ferrous-sulfide (iron II sulfide) scale typically forms in the wellbore under anaerobic conditions and may cause a reduction in well productivity. It has been proposed that ferrous ions react with bisulfide formed from dissolved hydrogen sulfide to form a complex iron bisulfide intermediate, which further reacts to produce black solid ferrous sulfide. Treatment of this type of scale typically involves mineral acids or chelants, which themselves provide additional challenges for pipeline integrity.

The Weatherford flow assurance laboratory carries out tests that determine the best inhibitors for scale problems. Compared to calcite, barium, and gypsum scales, little work has been done to study prevention of ferrous sulfide scale. For calcite, barium, and gypsum scales, the dynamic-flow loop is commonly used. However, for ferrous-sulfide scale, there is a challenge for a quick and reliable test method. The preparation of ferrous sulfide under sour conditions is not straight forward due to both the difficulty in achieving sufficiently anaerobic conditions and the associated hazards of managing H2S. The presence of oxygen will result in ferric sulfide instead of ferrous sulfide.

This paper describes in detail laboratory experiments to safely prepare ferrous sulfide scale using H2S and also test potential inhibitors. Comparisons were made between using metal sulfide instead of H2S. Using the H2S method to prepare ferrous sulfide provided a quick and robust way to select potential inhibitors under various conditions, which can be used to improve flow assurance assessments.

This paper will demonstrate selected chemicals compared to tetrakis (hydroxymethyl) phosphonium sulfate (THPS) in preventing the formation of ferrous sulfide under sour conditions and ambient or elevated pressures and temperatures when applied at low concentrations. Some inhibitors that are successful under sour ferrous sulfide preparations are not effective when metal sulfide ions are used instead of H2S, which means potential inhibitors are being missed due to inappropriate test methods.

Overall, a technological advancement was made with an anaerobic and sour method to test effectively ferrous sulfide inhibitors that would perform at low concentrations.
New Methodologies for Human Factors in Process Safety
Authors: James B.
Published: February 2021

Process Safety has been a major focus for the Oil and Gas and Petrochemical industries since the Flixborough disaster of 1974. Through the efforts of leaders in Safety there have been a number of key methodologies that has assisted Process Safety professionals in identifying “what went wrong” and how do we learn from disasters to prevent similar incidents from occurring again. Industry professional Dr. Trevor Kletz has gone as far as saying “Organisations have no Memory” Kletz (1993). However, over the last few decades, the industry seems to be making the same mistakes every few years. Research, insight and well-structured root cause analysis has highlighted that Human Factors and Organisational Culture is an area that must be considered in understanding Process Safety related incidents. Organisations such as the Centre for Chemical and Process Safety has included Human Factors as one of the elements in the Management System for Process Safety. System thinking and system dynamics has been identified a way of thinking about and analysing Process Safety related incidents to understand the Human Factor and its role in process related incidents.
Achieving Long Term Well Integrity: An Engineered Solution for Production Casing in a Deepwater Environment
Authors: Reveth V. , Giron Rojas R. , Gupta N. , Gonzaga E.
Published: February 2021

In a deepwater environment, any remedial operation has a high impact on the overall costs during the life of the wells. The zonal isolation can be compromised due to the exposure of the well's main components (casing and cement) to the changes in the stress conditions. The changes in wellbore conditions can occur during the drilling, production, intervention, and decommissioning stages. Typically, conditions such as fluid pathway and high formation pressure are sufficient to lose zonal isolation. The fluid pathway can be a fissure, an induced crack in the cement sheath, a mud channel, a micro-microannulus, or changes in the cement matrix permeability. As a result of the oil industry technology developments, progresses, the advanced stress-modelling software and the availability of cement and rock properties property data have enabled to an improved understanding of the cement behavior under stress. Prevention of the loss of the hydraulic isolation provided by the primary cementing in the annulus can be assessed by predicting the mechanical failure of the cement sheath. Formation geo-mechanics is one of the main factors that help in designing a robust cement system for changing stresses. Furthermore, the consequence result of the cement sheath failure can be mitigated by the placement of placing a self-healing cement (SHC) system to maintain long-term zonal isolation.

An interdisciplinary approach can be used to determine the following: Understand the impact of the well plan, and fluid densities on well integrity, in addition to cementing best practices.Characterize typical deepwater field formations, and establish limits for geo-mechanical values of each layer.Identify critical factors and focus on the pay zones.Understand potential issues and communication between the pay zones and the aquifers that are already previously confirmed.Determine risk of zonal communication assessment, mitigation, and prevention measurement implementations

Once the formation data is validated by the operator, the life cycle of the well is simulated and the risk of zonal isolation can be evaluated. The results of this assessment can help the operator choose between to take the approach of mitigation, prevention, or a combination of both. The objective is to place a robust cement sheath with advanced mechanical performance in the pay zones that can resist the failures due to changing stresses during the well testing and production. This paper uses presents examples from a deepwater development field to show how cement systems with advanced mechanical properties counter the critical stresses during the lifecycle of a well and maintain zonal isolation.
A Fundamental Model for Predicting Oil Recovery Due to Low Salinity Water Injection in Carbonate Rocks
Authors: Al-Shalabi E. W. , Sepehrnoori K. , Pope G. , Mohanty K.
Published: February 2021

The low salinity water injection (LSWI) technique is gaining popularity due to the simplicity of the method compared to other thermal and chemical EOR techniques. In this paper, a fundamental model is proposed which captures the effect of LSWI on improving the microscopic displacement efficiency from carbonates through the trapping number. The proposed model was used to history match recently published corefloods using the UTCHEM simulator. The proposed model incorporates wettability alteration effect through contact angle and trapping parameter. Results showed that history matching of the corefloods was performed successfully using the proposed model. Moreover, wettability alteration is the main contributor to LSWI effect on oil recovery from carbonate rocks. The proposed model was further validated upon which the applicability is extended to include weakly-oil-wet to mixed-wet rocks. This model can be used for oil recovery predictions from carbonate rocks at the field-scale.
Geomechanics: a New Star in the Horizon to Change the Fortunes in E&P Projects
Authors: Hegazy M. , Lakshmikantha M.R.
Published: February 2021

The E&P industry all over the world is awakening to the new technology discipline of Geomechanics, recognizing its importance in every operation of hydrocarbons exploitation, from drilling to production. There are specific applications in the early stage of exploitation, e.g. with respect to wellbore stability, sand production, hydraulic fracturing, traversing depleted zones, characterization of fractures and fault sealing capacity. In the later stages of production it can better characterize reservoir subsidence and fracture behavior with pressure evolution. A rigorous application of these methods can add important value to E&P projects. The need for innovative ways to solve the technology challenges planted the seeds of Geomechanics to germinate and grow as a key technology in E&P industry with applications for present and future projects. The vision for the future of this emerging discipline is bright with strong growth in applications. It is especially relevant to meet the challenges posed by many new discoveries, especially unconventional plays, which are often difficult to develop profitably. Geomechanics creates opportunities for improved and integrated project management. It can offer a variety of solutions by integrating conventional E&P technologies with cutting edge numerical, mathematical models that impacts the reservoir production behavior. Major operators were the first to embrace the scientific use of Geomechanics to help develop difficult reservoirs profitably. Also, a few medium-sized oil companies have recognized this potential and, as a consequence, have created Geomechanics teams with in. In this article, the authors provide a bird's eye view of Geomechanics as a core E&P technology supporting mega E&P projects. We discuss the current state of the art of this technology, with special emphasis on applications.
Feasibility Study on the Implementation of CO2-EOR Coupled with Sequestration in Trinidad via Reservoir Simulation
Authors: Narinesingh J. , Boodlal D. V. , Alexander D.
Published: February 2021

The paper seeks to assess the technical and economic feasibility of implementing carbon dioxide enhanced oil recovery (CO2 EOR) in Trinidad and Tobago from flue gas production whilst mitigating the effect of greenhouse gases via CO2 sequestration. An existing power plant in Trinidad was selected as the CO2 source. As such, actual CO2 volumes and properties were found and used in this analysis. However, a hypothetical field was chosen as the appropriate sink, which can be analogous to a field in onshore Trinidad.

A detailed reservoir model was built using the compositional fluid model CMG-GEM. Various scenarios were simulated to determine the optimum number of producers for primary production and the best location of the injectors for CO2 EOR. The optimum number of producers for the reservoir during primary production was found. In addition, the most favorable location of the injector to avoid early breakthrough and increase oil recovery was also determined.

Many key parameters were reported from this investigation. These included OIIP, forecasted production and primary recovery. After primary production, CO2 EOR was then implemented with the use of the reservoir and fluid models and the additional recovery is reported. Other Key CO2-EOR parameters such as CO2 utilization rate and total sequestered CO2 were also quantified.

Though a hypothetical reservoir was used, all associated data were defined and once an actual reservoir is known, the same technically rigid methodology can be applied.

The OIIP was found to be 6.74 MMSTB for the selected reservoir. Based on an economic net present value (NPV) assessment, the optimum number of production wells for field development was found to be 3. At the end of primary production from these three wells (with 2.375 in. tubing), a total of 1.83 MMSTB were produced. This corresponded to a primary recovery factor of 27.2% over 4 years and 2 months.

For CO2 EOR coupled with sequestration, these three wells were manipulated and used as 1 injector and 2 producers. CO2 EOR led to another 1.07 MMSTB of recovery for a total of 2.9 MMSTB (43.04% Recovery) for the ten year life of the project. A total of 5427 MMSCF (287 000 tons) of CO2 was sequestered in the reservoir (40.39% Storage) at an injection pressure of 1400 psi.
The Analysis and Interpretation of Parameters on Well Performance of Low Permeability Water-Producing Reservoirs: a Case Study of Daniudi Gas Field
Authors: Li Y. , Li X. , Shi J. , Wang H. , Wu L. , Xu D. , Teng S.
Published: February 2021

Predicting the effects of reservoir and well parameters on the performance of multi-fractured horizontal wells in low-water-producing reservoirs is very important in determining which operations should be taken for improving the gas recovery. Due to the increased number of horizontal wells drilled in Daniudi gas field, there is a necessity for a better and improved understanding of the behavior and performance.

In this case, a linear regression model approaches for developing prediction the performance from well data of Daniudi gas field. The linear regression model has been developed relationships among the performances, reservoir and well parameters. The results show that the performances are not only functions of permeability, pressure drops, gas saturation, number of fractures, length of horizontal well, but also related with some special parameters such as drilling-encounter rate, flowback rate, water gas ratio. Additionally, the linear regression model is corrected by considering the problem of liquid loading. Finally, the sensitivity analyses of these parameters have been studied and the parameters have been ordered according to the degree of sensitivity. This study is very important for understanding the main influence parameters on the performance in Daniudi gas field, which play a significant role for further operations to improving the performances.
Investigation of Significance of Critical Components in Optimization of WAG Injection Processes under Uncertainty
Authors: Temizel C. , Purwar S. , Agarwal A. , Abdullayev A. , Urrutia K. , Chacon-Garcia A.J.
Published: February 2021

Water alternating gas (WAG) injection has been widely used for the last 50 years throughout the world. The typical improved oil recovery (IOR) potential for WAG injection compared with water injection is 5 to 10%. It was originally intended to improve sweep efficiency during gas flooding, with intermittent slugs of water and gas designed to follow the same route through the reservoir. Mechanisms in WAG injection include microscopic effects, particularly in cases where three-phase flow and hysteresis are important for the IOR effect. Injection of gas usually aids an ongoing waterflood, and finding technical and commercial methods to reduce gas costs would be useful. Water injection alone tends to sweep the lower parts of a reservoir, while gas injected alone sweeps more of the upper parts of a reservoir because of gravitational forces. Gas represents a large fraction of the total cost, making WAG injection an expensive method. Thus, optimizing WAG injection is not only crucial in terms of recovery but also economics, especially where gas is expensive and/or limited. In this study, the significance of key components in a WAG injection process on SPE's 5th Comparative Solution Project (CSP) is presented that models the WAG process through a pseudo-miscible formulation by means of coupling a full-physics reservoir simulator with commercial optimization and uncertainty software. The results are analyzed and presented in a comparative manner by means of tornado charts showing the significance of each decision and uncertainty variable.
Using Polymer Alternating Gas to Maximize CO2 Flooding Performance
Authors: Li W. , Schechter D. S.
Published: February 2021

Carbon dioxide (CO2) has been used commercially to recover oil from reservoirs by enhanced oil recovery (EOR) technologies for over 40 years. Currently, CO2 flooding is the second most applied EOR processes in the world behind steamflooding. Water alternating gas (WAG) injection has been a popular method to control mobility and improve volumetric sweep efficiency for CO2 flooding. The average improved recovery is about 9.7%, with a range of 6 to 20% for miscible WAG injection. Despite all the success of WAG injection, sweep efficiency during CO2 flooding is typically a challenge to reach higher oil recovery and better apply the technology.

This paper proposes a new combination method called polymer alternating gas (PAG) to improve the volumetric sweep efficiency of the WAG process. The feature of this new method is that polymers are added to water during the WAG process to improve mobility ratio. In the PAG process, polymer flooding and immiscible/miscible CO2 injection are combined.

To analyze the feasibility of PAG, models considering both miscible and polymer flooding processes are built to study the performance of PAG. In this paper, the sensitivity of polymer adsorption and concentration are studied. The feasibility of PAG in reservoirs with different permeabilities, different Dykstra-Parsons permeability variation coefficients (VDPs), and different fluids are also studied. A reservoir model from a typical section of the North Burbank Unit (NBU) is used to compare the performance between PAG, WAG, and polymer flooding. This study demonstrates that PAG can significantly improve recovery for immiscible/miscible flooding in homogeneous or heterogeneous reservoirs.
Can Indigenous Bacteria be Utilized for Increasing Oil Recovery from Trinidad Oil Reservoirs?
Authors: Rambaran N. , Maharaj S. , Hosein R.
Published: February 2021

In Microbial Enhanced Oil Recovery (MEOR) oil mobility and oil recovery is increased by growing and reproducing microbes (bacteria) in oil reservoirs. The oil reservoir is either innoculated with a proprietry bacteria and then fed to grow or indigeneous microbes present are fed by the injection of a suitable nutrient identified from labotatory experiments. The metabolic by-products produced by these microorganisms causes a reduction in oil viscosity and interfacial tension and an increase in oil mobility. Although MEOR is not popular, the open literature has shown this to be a low cost mechanism that can be implemented with waterflood projects to increase the recovery of residual oil by another 1-5 %.

In this study an oil sample from an oil reservoir in the South of Trinidad was selected and the indigenous bacteria present was identified to be mainly of the Bacillus species. A quantification of this indigenous bacteria by plate counts showed that the aerobic colony forming units (CFU) was about 1.5×106 CFU/ml whereas the observed anaerobic plate counts was about 9.0×102 CFU/ml. Growth of the indigenous bacteria was stimulated by innoculating the oil sample with five different nutrient formulations for a period of three weeks so as to select the most suitable nutrient. However, the growth in bacteria was too numerous to count even after one week.

Experimental measurements showed that the sample innoculated with the nutrient broth formulation had the greatest change in oil properties. The reduction in oil viscosity was 49 % and the reduction in interficial tension was 17 %. The results from this study can be included in waterfloood simulation studies for suitable oil reservoirs in Trinidad to determine the added increase in oil mobility and oil recovery from a combination of waterflood and MEOR.
Numerical Simulation of Shale Gas Development Based on Complex Fracture Network Growth
Authors: Ye D. , Yin C. , Li Y. , Wang S. , Qin G. , Chen H.
Published: February 2021

Micro-seismic result has shown that compared to conventional reservoir, more complex fracture network will be generated in shale gas reservoirs after hydraulic fracturing stimulations, which provides key channels for shale gas to flow in economic rate. It is vitally important to recognize complex fracture network and model such complex system to better understand gas develop process, optimize hydraulic fracturing design, and determine development plans of shale gas reservoirs.

Our proposed model enable realistic modeling of complex fracture network growth even with some uncertainty (SPE 157411), but it is possible to represent large-scale fracture network distribution in reservoir modeling and numerical simulation of shale gas development. In this paper, we used this proposed model to generate hydraulic fracture network distribution in shale formation, taking into account interaction between hydraulic fracture and actual large-scale natural fractures. Integrating hydraulic fracture network results and natural fractures in non-stimulated area, highly constrained unstructured gridding and a connection list are constructed, using the Discrete Fracturing Modeling (DFM) method. This model can effectively predict production performance. With real-world well data, the simulation system calibration is done, and the simulated well production performance has good agreement with real-world producing data. Using this simulation system, effective stimulated reservoir volume (ESRV) is also predicted.

The proposed approach is capable of modeling complex fracture network propagation and predicting well producing rate, if information data on multi-scale pre-existing natural fracture is available. This approach provide one opportunity to predict well production performance and effective stimulated reservoir volume (ESRV), which is also significant for shale gas development plan.
Chemical Deliquification of Unconventional Gas Wells
Authors: Francis-LaCroix K. , Seetaram D.
Published: February 2021

Trinidad and Tobago offshore platforms have been producing oil and natural gas for over a century. Current production of over 1500 Bcf of natural gas per year (Administration, 2013) is due to extensive reserves in oil and gas. More than eighteen of these wells are high-producing wells, producing in excess of 150 MMcf per day. Due to their large production rates, these wells utilize unconventionally large tubulars 5- and 7-in.

Furthermore, as is inherent with producing gas, there are many challenges with the production. One major challenge occurs when wells become liquid loaded. As gas wells age, they produce more liquids, namely brine and condensate. Depending on flow conditions, the produced liquids can accumulate and induce a hydrostatic head pressure that is too high to be overcome by the flowing gas rates. Applying surfactants that generate foam can facilitate the unloading of these wells and restore gas production.

Although the foaming process is very cost effective, its application to high-producing gas wells in Trinidad has always been problematic for the following reasons: Some of these producers are horizontal wells, or wells with large deviation angles.They were completed without pre-installed capillary strings.They are completed with large tubing diameters (5.75 in., 7 in.).

Recognizing that the above three factors posed challenges to successful foam applications, major emphasis and research was directed toward this endeavor to realize the buried revenue, i.e., the recovery of the well's potential to produce natural gas. This research can also lead to the application of learnings from the first success to develop treatment for additional wells, which translates to a revenue boost to the client and the Trinidad economy. Successful treatments can also be used as correlations to establish an industry best practice for the treatment of similarly completed wells.

This paper will highlight the successes realized from the treatment of three wells. It will also highlight the anomalies encountered during the treatment process, as well as the lessons learned from this treatment.
Efficient Proppant Flowback Prevention Strategy Allows Production of a Multi Fractured Offshore Horizontal Well Equipped with ESP and Screenless Completion
Authors: Martocchia F. , Baretti S. , Farina L. , Rizza G. , Okassa F. , Dirya A. D. , Haaland T. G.
Published: February 2021

When production facilities are not equipped with a solid control device, proppant flowback becomes an issue throughout the entire productive life of a screenless multi fractured well. The challenge of minimizing proppant flowback is even more critical when dealing with offshore horizontal wells with ESP systems installed.

A wide selection of proppant flowback prevention additives is now available in the industry: most of them work either chemically or mechanically. At low formation temperature (150 F), the effectiveness of some additives such as resin coated proppant or fiber can be limited due to the temperature activation.

This paper will describe a successful strategy of proppant flowback control which was implemented in a multi stage fracturing treatment on a horizontal well in M- field, offshore Congo. It is the combination of resin coated proppant, enhanced by a chemical activator and inert fibers that provides double mechanism to eliminate proppant flowback issues during well production and sustaining life of ESP.

Success in this multi stage fracturing treatment has resulted in oil production from a pay zone that has never been produced due to poor petrophysical characteristics.

This document will describe: proppant flowback control additives selection process, placement strategy, hydraulic fracturing design and well execution considerations for multi stage fracturing treatments.
The Impact of Laminated Rock on Hydraulic Fracture Propagation in Unconventional Resources
Authors: Cherian B.V. V , Higgins-Borchardt S. , Bordakov G.A. , Yunuskhojayev A. , Al-Jalal Z. , Mata D. , Jeffers J.
Published: February 2021

As unconventional reservoirs continue to be discovered and appraised, an ever increasing challenge is to understand the productive mechanism that unlocks the potential of these reservoirs. Since most unconventional reservoirs have some degree of lamination (varying from a few hundreds of an inch to a couple of feet), a technical hurdle exists in understanding the integration of conventional logging (using up-scaled measurements), modeling software (assumptions, gridding, numerical/P3D) and fine scale measurements (core measurements).

Laminated reservoirs pose many challenges in the decision making process especially when a model centric, data driven approach is utilized. These challenges can be reduced to two categories: (1) challenges in understanding fracture propagation mechanism and (2) challenges in reservoir characterization. This paper focuses on a procedure to capture the former. The early phase of gathering measurements is frequently executed with data sets and measurements that are incomplete and insufficient to understand the production mechanism in these low porosity environments. In an engineering analysis, this data may be utilized only to a limited extent, due to the inconsistences in the measurements gathered at various scales. To overcome these inconsistencies a novel approach to estimate mechanical properties with sub-sonic resolution through integration of sonic logs, high resolution logs, and facies classification has been developed.

The use of traditional workflows to derive mechanical properties has led to overestimating and/or underestimating rock strength and stress in the different layers. This, historically, has resulted in inconsistent conclusions across various disciplines and unexplainable well performance. Furthermore, the process of matching hydraulic fracture net-pressure using conventional workflows can result in the complication of fracture propagation process or incorrect calibration of the Mechanical Earth Model used to estimate earth stresses. We have demonstrated that the presented workflow allows for more accurate estimation of the mechanical properties profile in thin bed formations and consequently more effective use of those estimates to design hydraulic fractures and analyze the results.