bluuebunny/crossref_metadata_2025 huggingface dataset:
A Mathematical Model to Predict Solvent/Steam Flashing in Pure Solvent or Solvent/Steam Coinjection in Horizontal Producers
Authors: Irani Mazda , Sabet Nasser , Bashtani Farzad , Gohari Kousha
Published: February 2021

Although the steam assisted gravity drainage (SAGD) process is still the preferred thermal-recovery process method for Athabascan deposits in Alberta, Canada, the interest in solvent-based techniques is growing due to reduce greenhouse-gas (GHG) emissions and water treatment concerns. In SAGD process, the thermodynamic trapping or subcool trapping is quite efficient due to strongly dependency of bitumen viscosity to temperature. As Irani (2018) discussed subcool trapping for solvent applications such NsolvTM recovery process is inefficient due to week dependency of solvent viscosity to temperature. Other factor that effects the efficiency of the thermodynamic trapping is that the pure solvent injection recovery processes are operated at low pressure and it is not large temperature window for operators to apply large subcools. Such challenges make the pure solvent injection recovery processes a perfect case for deployment of Flow-Control-Devices (FCDs). FCDs have demonstrated significant potential for improving recovery in SAGD production wells. FCD experience in SAGD has been primarily positive and most producers performed better with FCDs. Application of FCDs are even more important in pure-solvent injection recovery processes due to large amount of solvent in the liquid pool and also low latent heat of solvent in comparison of water. With FCDs, the draw-down pressure is typically higher, resulting in flashing near the well bore, which is largely correlated to latent heat of the main fluid in the liquid pool.

The flashing creates either steam or vapour breakthrough that causes the reduction in the relative permeability of the liquid phase. Such mobility reduction creates new equilibrium that stabilizes at lower rates. Such new equilibrium analysis is conducted by forcing a new temperature gradient to the model. Such condition creates an environment that leads into extensive solvent-breakthrough called solvent-coning in this study. The main output of such analysis is the produced solvent gas-fraction produced at the sand-face. The gas-fraction is an important input for the flow control devices (FCDs) especially at subcools close to the zero, as it controls its behavior. EoS model is also created and simplified to be possible to used in defining different equilibrium conditions. This type of analysis can help the operators evaluate the effectiveness of different type of FCDs, whether they are primarily momentum- or friction-style devices for application of the pure solvent injection recovery processes. This study is the first of its kind that couple the EoS and Darcy flow in the liquid pool. The model includes all the factors into a liquid-relative-permeability, and limitation of the liquid flow into producer is modeled by Darcy flow and reduction of such relative-permeability.
Well Integrity Issues in Steam Flood Injection Wells, Karim Small Field Cluster
Authors: Ariwibowo Alexis , Al Sulti Al Salt , Al Aufi Yousuf , Mirza Muhammad
Published: February 2021

Two (2) steam flood vertical injection wells are under operation for the last 15 months in a two- pattern pilot. Previous steam injection experience in this reservoir did not indicate serious issues due to the short injection periods for cyclic steam stimulation (CSS) but several well integrity issues have been faced during the steam flood period. Key issues include high wellhead growth, steam leak to the annulus A, annulus between 7” production casing and 4-1/2” injection tubing, and groundwater vapor behind 9.625” surface casing. Negative impacts from these issues on the continuity and effectiveness of the steam flood are recognized and need to be resolved comprehensively.

All wells in the steam flood pilot were drilled and completed based on designs and procedures according to thermal well compliance including well equipment, and cementing specification. Production casing was equipped with thermal expansion collars to support reduction in wellhead growth. Completion strategy uses seal bore packer with bore extensions to accommodate tubing movement and Vacuum-Insulated-Tubing to provide maximum thermal insulation. However, the presence of a total- loss zone near the surface (starting from 50 m depth) affects the cement isolation between surface casing and 12.25” open hole. Daily monitoring is performed on each well where key injection parameters and well responses are recorded.

Maximum wellhead growth reached 61 cm within the first week and steam leak from the injection string to annulus A started after 6 months of steam injection. Soon after that, groundwater vapor starts to arise from the gap between 9.625” casing and 12.25” open hole. These series of failures occurred in both injection wells within 3 months apart from each other. It is believed that the steam leak to annulus A resulted in thermal transmission to groundwater vapor. Hoist entries to both injectors indicated that Injector-1 has tubing seal assembly stuck inside seal bore and resulted in parted tubing collar while Injector-2 has tubing seal assembly damage. Both wells have thick oil covering the retrieved seal bore packer. Remedial actions were performed, including a complete change-out of the seal bore packer assembly and top-job cement fill up to surface using fast-set cement to isolate the gap between 9.625” casing and 12.25” open hole to reduce wellhead growth. As a result, the maximum wellhead growth became only 19 cm and 4 cm in Injector-1 and Injector-2, respectively. These remedial actions also led to restoring well and thermal integrity.

Retrieved seal bore packer was sent back to manufacturer for appropriate failure analysis and providing useful feedback reports on the above issues. Monitoring and observation data along with failure analysis should provide vital information and possible improvement in completion strategy for steam injection wells that are planned for continuous steam flood projects in similar reservoirs.
Performance Analysis of Infill Wells Adjacent to SAGD Well Pair: Non-Condensable Gas NCG Breakthrough
Authors: Irani Mazda , Tuttle Aubrey , Stevenson Jesse
Published: February 2021

Late in the life of the Steam Assisted Gravity Drainage (SAGD) process, it has become common practice to drill a single, horizontal infill well (called a “Wedge Well™” by some) in the oil bank located between two mature SAGD well pairs to produce the bitumen that has been heated and mobilized but is unable to be effectively drained by gravity given the largely lateral location relative to that of the SAGD producers. Since this oil bank is surrounded by the large, depleted steam chamber created by the existing well pairs, it requires little heat to mobilize bitumen. One of the challenges, however, in producing infill wells is that non-uniform drainage and local hot spots can be readily created in the first year of their operation, that in many cases require completion retrofits, such as with Flow Control Devices (FCDs), to improve the drainage profile. Installation of FCDs in these wells is quite challenging since the dynamics of the infill wells is changing with time and there is limited time to achieve conformance.

To maintain pressure in SAGD chambers the common practice is to inject non-condensable gas (NCG). NCGs, such as methane, which is most common, do not condense in the steam chamber. Some of these NCG can short-cut into the infill through the existing hot-spot. The main reason is that the hot sections of infills are locations that are closer to the SAGD steam chamber, and due to steam condensate encroachment and higher mobility create a pathway for NCG breakthrough. FCDs are designed to promote a more uniform flux distribution along the producer, and exposure to NCG can change the impact of the FCDs. The true hot-spot temperature after NCG injection is decreasing and this can be mistaken as FCD efficiency and steam blocking. In reality, this temperature reduction is due to partial pressure effects associated with NCG encroachment. In this study, a new thermodynamic model is created to explain the NCG encroachment into infill wells, and a new temperature profile along the producer as a function of NCG breakthrough is calculated. The purpose of this work is to create a productivity index (PI) relationship that is fit for purpose for infill wells adjacent to SAGD well-pairs with NCG breakthrough that can primarily be used for analysis and optimization of SAGD FCD completions. This model can also be used to evaluate FCD performance in infill wells pre- and post- NCG breakthrough.
Pore-Scale Simulation of Calcite Matrix Acidizing with Hydrochloric Acid
Authors: HaghaniGalougahi MohammadJavad
Published: February 2021

A continuum hydrodynamic model with immersed solid/fluid interface is developed for simulating calcite dissolution by hydrochloric acid (HCl) at the pore scale, and is most accurate for a mass-transfer-controlled dissolution regime under laminar flow conditions. The model uses averaged Navier-Stokes equations to model momentum transfer in porous media and adopts a theoretically developed mass-transfer formulation with assumptions. The model includes no fitting parameter and is validated using experimental results. The findings of previous research and existing models are briefly discussed and their shortcomings and advantages are elucidated. The present model is used in some pore-scale simulations on hypothetical but realistic cases, investigating the evolution of Darcy-scale permeability. Darcy-scale permeability exhibits totally different functionality of porosity in different dissolution regimes.
Reserves Determination Using Type Curve Matching and Extended Material Balance Methods in the Medicine Hat Shallow Gas Field
Authors: West S. L. , Cochrane P. J. R.
Published: February 2021

Tight shallow gas reservoirs in the Western Canada Basin present a number of unique challenges in accurately determining reserves. Traditional methods such as decline analysis and material balance are inaccurate due to the formations' low permeabilities and poor pressure data. The low permeabilities cause long transient periods not easily separable from production decline using conventional decline analysis. The result is lower confidence in selecting the appropriate decline characteristics (exponential or harmonic) which significantly impacts recovery factors and remaining reserves. Limited, poor quality pressure data and commingled production from the three producing zones results in non representative pressure data and hence inaccurate material balance analysis.

This paper presents the merit of two new methods of reserve evaluation which address the problems described above for tight shallow gas in the Medicine Hat field. The first method applies type curve matching which combines the analytical pressure solutions of the diffusivity equation (transient) with the empirical decline equation. The second method is an extended material balance which incorporates the gas deliverability theory to allow the selection of appropriate p/z derivatives without relying on pressure data.

Excellent results were obtained by applying these two methodologies to ten properties which gather gas from 2300 wells. The two independent techniques resulted in similar production forecasts and reserves, confirming their validity. They proved to be valuable, practical tools in overcoming the various challenges of tight shallow gas and in improving the accuracy in gas reserves determination in the Medicine Hat field.
Well Design and Successful Field Installation of Openhole Sand Control Completions with Acid Stimulation in a Highly Deviated Well in Vietnam
Authors: Vu Hung , Tran Son , Nguyen Trang , Kannan Bharathwaj , Tran Khoa , Nguyen Thong
Published: February 2021

Application of openhole sand control technology is becoming mandatory in the field, particularly with the given uncertainty in geomechanics, challenges to wellbore integrity while drilling, and sand production during the life of the well. The completion equipment readiness and success of the installation can be challenging in the event of extending the horizontal section to accommodate geological heterogeneity and maximizing well productivity. This paper discusses operational excellence recorded in Well A, in the Thang Long Field, offshore Vietnam, from well design perspectives ensuring maximum reservoir contact to outcome of well completion.

The well was targeted in the Oligocene reservoir, a thin oil rim with large gas cap overlay, and required drilling and completion for 1126 m horizontal length of 8 1/2-in. open hole. The completion design included multiple swellable packers for isolation of unwanted zones, 6 5/8-in. basepipe sand screens for the production zones, and a fluid loss control device to help prevent undesirable losses. Several torque and drag simulations were performed to help predict potential threats that could be encountered during completion string deployment or during space out of the inner wash pipe string.

One apparent challenge of this completion design was to deploy the lower completion string to total depth (TD) per stringent reservoir requirements, resulting in an approximate 1126 m length of the string in the horizontal section. Another task was to facilitate manipulating 1130 m of wash pipe inside the completion string to locate the seal assemblies accurately at the corresponding seal bore extension positions for effective acidizing treatment. Although these were long sections of completion string and wash pipe, the quality of acidizing stimulation to effectively remove mud cake should not be compromised to ensure positive production rates.

During operations, the completion string was run to target depth without any issue, and the wash pipe was spaced out and manipulated correctly. These operations subsequently led to a successful acidizing treatment and the proper closure of the flapper type fluid loss device. The completion design and operation were concluded successfully, significantly contributing to field production performance to date.

The novelty of the completion design and installation is the ability to deploy an 1126-m lower completion in long, highly deviated and horizontal openhole section coupled with acid stimulation in reasonable time and as per plan.
Impact of Data Quality on Well Operations: Case Study of Work-over Operations
Authors: Enyekwe Alfred , Urubusi Osahon , Yekini Raufu , Azoom Iorkam , Isehunwa Oloruntoba
Published: February 2021

Significant emphasis on data quality is placed on real-time drilling data for the optimization of drilling operations and on logging data for quality lithological and petrophysical description of a field. This is evidenced by huge sums spent on real time MWD/LWD tools, broadband services, wireline logging tools, etc.

However, a lot more needs to be done to harness quality data for future workover and or abandonment operations where data being relied on is data that must have been entered decades ago and costs and time spent are critically linked to already known and certified information.

In some cases, data relied on has been migrated across different data management platforms, during which relevant data might have been lost, mis-interpreted or mis-placed. Another common cause of wrong data is improperly documented well intervention operations which have been done in such a short time, that there is no pressure to document the operation properly. This leads to confusion over simple issues such as what depth a plug was set, or what junk was left in hole.

The relative lack of emphasis on this type of data quality has led to high costs of workover and abandonment operations. In some cases, well control incidents and process safety incidents have arisen. This paper looks at over 20 workover operations carried out in a span of 10 years. An analysis is done on the wells’ original timeline of operation. The data management system is generally analyzed and a categorization of issues experienced during the workover operations is outlined. Bottlenecks in data management are defined and solutions currently being implemented to manage these problems are listed as recommended good practices.
Rock Compressive Strength: A Correlation from Formation Evaluation Data for the Niger Delta
Authors: Salawu Babatunde , Sanaee Reza , Onabanjo Olumayowa
Published: February 2021

The purpose of this paper is to study the strength of rocks by determining their Unconfined Compressive Strength (UCS), correlate the determined strength to physical properties of rocks that can be measured from formation evaluation data and derive an equation that can be used to derive rock strength from formation evaluation measurements. The scope of this work is limited to the Niger delta basin from which core samples were taken.

The method used for this research was to collect data of existing core samples at different depths and in various fields in the Niger Delta, then determine the strength of each sample by unconfined compressive tests. The derived strength was then analyzed with corresponding formation evaluation data utilizing regression analysis. Then, comparisons were drawn between the correlations derived and other existing correlations in the industry to check whether any of the existing correlations fits the Niger Delta region.

The result is a model that takes formation evaluation data (Slowness, Young's Modulus and Poisson's ratio) as input in order to provide rock compressive strength for the Niger-Delta region. It was also observed that correlations built for other regions of the world do not yield accurate results when used for the Niger Delta region due to factors such as formation characteristics type of regression method, various sample collection conditions and so on.
Innovations of Gas Lift in Prolific, Long-perforations, and Multilayered Wells, Case Study in Sudan
Authors: Tang Xueqing , Dou Lirong , Wang Ruifeng , Wang Jie , Wang Shengbao , Wang Jianshun , Shi Junhui
Published: February 2021

Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The wells have high flow capacities, producing from long-perforation interval of 3,911 ft (from 4,531 to 8,442 ft). Production mechanisms include gas injection in downdip wells and traditional gas lift in updip, zonal production wells since the start-up of field in July, 2010. Following pressure depletion of oil and condensate-gas zones and water breakthrough, traditional gas-lift wells became inefficient and dead. Based on nodal analysis of entire pay zones, successful innovations in gas lift have been made since March, 2013. This paper highlights them in the following aspects: Extend end of tubing to the bottom of perforations for commingled production of oil and condensate gas zones, in order to utilize condensate gas producing from the lower zones for in-situ gas lift.Produce well stream from the casing annulus while injecting natural gas into the tubing.High-pressure nitrogen generated in-situ was used to kick off the dead wells, instead of installation of gas lift valves for unloading. After unloading process, the gas from compressors was injected down the tubing and back up the casing annulus.For previous high water-cut producers, prior to continuous gas lift, approximately 3.6 MMcf of nitrogen can be injected and soaked a couple of days for anti-water-coning.Two additional 10-in. flow lines were constructed to minimize the back pressure of surface facilities on wellhead.

As a consequence, innovative gas-lift brought dead wells back on production, yielding average sustained liquid rate of 7,500 bbl/d per well. Also, the production decline curves flattened out than before.
Mathematical Model of Energy Storage in Gas Hydrate and its Flow in Pipeline Systems
Authors: Akinsete Oluwatoyin , Isehunwa Sunday
Published: February 2021

Natural gas, one of the major sources of energy for the 21st century, provides more than one-fifth of the worldwide energy needs. Storing this energy in gas hydrate form presents an alternative to its storage and smart solution to its flow with the rest of the fluid without creating a difficulty in gas pipeline systems due to pressure build-up.

This study was design to achieve this situation in a controlled manner using a simple mathematical model, by applying mass and momentum conservation principles in canonical form to non-isothermal multiphase flow, for predicting the onset conditions of hydrate formation and storage capacity growth of the gas hydrate in pipeline systems.

Results from this developed model shows that the increase in hydrate growth, the more the hydrate storage capacity of gas within and along the gas pipeline. The developed model is therefore recommended for management of hydrate formation for natural gas storage and transportation in gas pipeline systems.
Mozambique Natural Gas Condensate Analysis: Offsetting Production Royalties with Production By-Products
Authors: Mazula Nelia
Published: February 2021

Oil is often produced in developing parts of the world with limited infrastructure where stakeholders are often challenged with comprehensive build-outs that include roads and even airports. In these environments production by-products such as natural gas condensates can be unfeasible to commercialize due to low quantities relative to the cost of processing and transportation. This study looks at work done in Mozambique on natural gas condensate characterization and commercialization studies to provide recommendations to new projects for facilities design and contract negotiation to consider ways of using production by-products, such as condensate, in the royalty negotiation process, especially in remote and developing regions. These results can also be used in future petroleum projects in Mozambique.
Advancing Models of Facies Variability and Lacustrine Source Rock Accumulation in Rifts: Implications for Exploration
Authors: Scholz Christopher A.
Published: February 2021

Important syn-rift hydrocarbon discoveries in the Tertiary East African Rift and in the South Atlantic subsalt basins have in recent years promoted renewed interest in the variability of source and reservoir rock facies in continental rifts. This talk considers several important new observations and developments in our understanding of the sedimentary evolution of lacustrine rift basins. Offshore subsalt basins in the South Atlantic demonstrate the importance of lacustrine carbonates, and especially microbialites, as reservoir facies in extensional systems. The role of rift-related magmatism is significant in these basins, both as drivers of hydrothermal systems around and within rift lakes, and as a source of solutes that facilitate carbonate accumulations. In the Tertiary East African Rift, substantial new hydrocarbon resources have been identified, including onshore siliciclastic reservoirs in remarkably young and shallow parts of the sedimentary section in the Albertine Graben. Rollover anticlines and fault-related folds serve as important structures for several new fields in the East African Rift, but larger structures affiliated with accommodation zones, in many instances located far offshore in the modern lakes, remain untested. Lacustrine source rocks that accumulated in stratified lake basins are the source of the oil and gas in these systems, however there is still much to be learned about their spatial and temporal variability. There is observed considerable variation in the character of organic matter on the floors of modern African lake basins, even adjacent ones. A number of factors likely govern the amount of total organic carbon preserved within the basins. These include 1) primary productivity; 2) degree of siliciclastic dilution, which is controlled in part by offshore slopes and the extent of onshore catchments, and 3) physical limnology, controlled by climate and basin-scale physiography, and the fetch-depth ratio of the lakes, which determines the likelihood of water column stratification. Scientific drilling in the African Rift lake basins is providing considerable information on the high temporal hydroclimate variability of the region, especially in the later Tertiary and Quaternary, which substantially controls basin lithofacies.
Integrated Geophysical Interpretation of Kerio Valley Basin Stratigraphy, Kenya Rift
Authors: Osukuku Godfred , Masinde Abiud , Adero Bernard , Wanjala Edmond , Ego John
Published: February 2021

This research work attempts to map out the stratigraphic sequence of the Kerio Valley Basin using magnetic, gravity and seismic data sets. Regional gravity data consisting of isotactic, free-air and Bouguer anomaly grids were obtained from the International Gravity Bureau (BGI). Magnetic data sets were sourced from the Earth Magnetic Anomaly grid (EMAG2). The seismic reflection data was acquired in 1989 using a vibrating source shot into inline geophones. Gravity Isostacy data shows low gravity anomalies that depict a deeper basement. Magnetic tilt and seismic profiles show sediment thickness of 2.5-3.5 Km above the basement. The Kerio Valley Basin towards the western side is underlain by a deeper basement which are overlain by succession of sandstones/shales and volcanoes. At the very top are the mid Miocene phonolites (Uasin Gishu) underlain by mid Miocene sandstones/shales (Tambach Formation). There are high gravity anomalies in the western and southern parts of the basin with the sedimentation being constrained by two normal faults. The Kerio Valley Basin is bounded to the west by the North-South easterly dipping fault system. Gravity data was significantly of help in delineating the basement, scanning the lithosphere and the upper mantle according to the relative densities. The basement rocks as well as the upper cover of volcanoes have distinctively higher densities than the infilled sedimentary sections within the basin. From the seismic profiles, the frequency of the shaley rocks and compact sandstones increases with depths. The western side of the basin is characterized by the absence of reflections and relatively higher frequency content. The termination of reflectors and the westward dip of reflectors represent a fault (Elgeyo fault). The reflectors dip towards the west, marking the basin as an asymmetrical syncline, indicating that the extension was towards the east. The basin floor is characterized by a nearly vertical fault which runs parallel to the Elgeyo fault. The seismic reflectors show marked discontinuities which may be due to lava flows. The deepest reflector shows deep sedimentation in the basin and is in reasonable agreement with basement depths delineated from potential methods (gravity and magnetic). Basement rocks are deeper at the top of the uplift footwall of the Elgeyo Escarpment. The sediments are likely of a thickness of about 800 M which is an interbed of sandstones and shales above the basement.
Evaluation of Anti-fouling Surfaces for Prevention of Mineral Scaling in Sub-surface Safety Valves
Authors: Charpentier T. V. , Neville A. , Baraka-Lokmane S. , Hurtevent C. , Ordonez-Varela J-R. , Nielsen F. Møller , Eroini V. , Olsen J. H. , Ellingsen J. A. , Bache Ø.
Published: February 2021

Mineral scale formation and deposition in down-hole completion equipment such as subsurface safety valves can cause dramatic and unacceptable safety risks and associated production losses and operational costs. Current scale removal strategies involve both mechanical and chemical technologies, each of them having their own advantages depending on the type of mineral scale and its location. However, these techniques are often costly and of limited efficiency.

The current study assesses the ability of a range of chemically and morphologically modified coatings to prevent/reduce mineral scale surface fouling. Building-up on previous work done under static conditions, this paper presents results from scaling tests under laminar and turbulent dynamic conditions using a rotating cylinder electrode under in a complex (mixed) scaling environment (supersaturated w.r.t. calcium carbonate, barium sulfate, strontium sulfate, barium carbonate and strontium carbonate). The study shows that if properly selected, surface treatments represent a promising approach to reduce scale deposition on downhole equipment surfaces that are critical to maintain equipment functionality and thereby well safety barrier integrity. By analyzing the scaling behaviors observed within the set of surfaces tested, suggestions of the controlling factors in anti-fouling on these systems are presented and discussed.
Synergistic Properties of Phosphonate and Polymeric Scale Inhibitor Blends for Barium Sulphate Scale Inhibition
Authors: Shaw S.S. , Sorbie K.S.
Published: February 2021

Barium sulphate is one of the most difficult types of scale to inhibit in oil and gas production systems, due to its physical hardness and its chemical and thermal stability. Barium sulphate is most commonly inhibited using either phosphonate or polymeric scale inhibitors (SIs) deployed at sub-stoichiometric concentrations. What is less well known in the oil industry is the effect of using combinations of two (or more) SIs synergistically for enhanced scale inhibition performance. A positive “synergistic” effect would be where, for example, 5ppm of A + 5ppm of B performed better than 10ppm of either A or B. In this paper, a series of static barium sulphate inhibition efficiency (IE) test results are presented, in which a series of pairs of SIs have been tested to determine their synergistic properties at pH 5.5 and 95°C. Polymers can be blended with phosphonates, or alternatively pairs of phosphonates or polymers may be applied. In all cases, the synergistic IE is compared with the IE of each SI tested independently at the mass dosage (i.e. the same concentration in mg/L or ppm). Each separate single SI used in the work has been tested previously for barium sulphate IE at pH 5.5, 95°C in order to determine the minimum inhibitor concentration (MIC) for each species (Shaw et al, 2012a, 2012b). Previously, 9 phosphonate and 9 polymeric SIs have been tested individually and, in this work, 34 SI combinations have been tested to examine their synergistic properties. The MICs of the synergistic blends are compared with the normal MICs of the individual SIs. Surprisingly, in most cases, the IE of the blends is usually higher over the range of SI concentrations tested (i.e. the MIC of the blend is lower), compared to that of each SI tested separately. Certain “pairs” of SIs used together yield a significantly beneficial effect, e.g. DETPMP and HMTPMP. Some mechanistic reasons why these synergistic pairs work particularly well are suggested.
Improving Scale Inhibitor Squeeze Design for Naturally Fractured Reservoirs
Authors: Spooner Victoria E , Stalker Robert , Wright Rob , Graham Gordon M
Published: February 2021

Scale Inhibitor (SI) squeeze treatments continue to be an important method for delivering chemical to the production system. However, while SI squeeze treatments in unfractured reservoirs can generally be readily simulated in matrix flow models, designing such treatments for application in fractured reservoirs is less routine, and resulting field treatment lifetimes can be disappointing. One reason for this is that the flow process and transport mechanisms by which the inhibitors are retained in fractured formations differs considerably from simple matrix flow. In this paper we expand upon previously published work examining the impact of squeeze treatment design on the outcome of a SI squeeze treatment for a fractured well using a novel fractured well squeeze model.

In previous papers, we highlighted the importance of diffusion-controlled transport of SI in low permeability tight matrix fractured reservoirs where little matrix flow is possible. In this paper, we report continuing developments of the fracture squeeze model and demonstrate how differences between advection and diffusion-controlled inhibitor transport can significantly alter the predicted squeeze treatment lifetimes, and suggest appropriate treatment design modifications to improve SI squeeze treatments in such fractured reservoirs.

This paper will demonstrate that such differences in transport mechanisms directly impacts the distribution of scale inhibitor within the near-wellbore region during the treatment phase. In fractured systems, this SI distribution is affected both by the extent of propagation of injection fluid through the fracture network and rate of diffusion into the surrounding matrix rock. This work examines the influence of factors such as injection rate, soak time, inhibitor diffusivity and retention/release properties on the matrix material.

By adjusting injection parameters such as injection rate and soak time in the treatment design, a more desirable distribution of scale inhibitor can be obtained, resulting in improved predicted treatment lifetimes. Thus, using the fracture squeeze model to provide a fuller simulation of the inhibitor transport, retention and release mechanism active in a fractured reservoir, we highlight potential placement issues for such reservoirs and demonstrate methods to improve squeeze design for fractured wells.
TOTAL's Experience on the Development and Implementation of a Scale Management Strategy in Central Graben Fields
Authors: Baraka-Lokmane Salima , Hurtevent Christian , Zhou Honggang , Saha Pratik , Tots Nourdine , Rieu Frédéric , Lastennet Ronan , Sugiarto Tomi
Published: February 2021

In Central Graben, North Sea, there is generally no free water production, most of the produced water is condensed water; however wells have been treated against scale build up at perforation level by performing acid washes using mainly acetic acid. Wells reacted differently after acid treatment: Some wells showed a significant productivity improvement, others showed good results but limited in time, some wells presented no gain after acid treatment and some other wells are scaling on a more aggressive basis after acidification. This paper shows that these behaviours are linked with the lithology of the different reservoirs. A better understanding on the scale formation and mechanism is essential in order to optimize the well intervention planning and timing to treat the wells. This study showed that calcium carbonate and sodium chloride are the only scale deposits susceptible to precipitate at the bottomholes of wells. The precipitation of sodium chloride has been induced by the high salinity of water associated with a high temperature at bottomholes as well as an inversion of the Joule- Thomson coefficient. Calculations showed that evaporation is slightly higher for Elgin reservoirs comparing to Franklin reservoirs, this is due to Joule-Thomson effect slightly stronger and a higher temperature reservoir for Elgin reservoirs. These high temperatures at the bottomholes induced the formation of calcium carbonate precipitation, this conducted to the loss of productivity. From the subsurface safety valve (SCSSV) to the surface facilities, the reduction of temperature caused a reduction of solubility of zinc sulphide and lead sulphide. In terms of chronology, halite scale occurred first, followed by carbonate scale and finally formation of sulphide scale at lower temperature.
Extreme Challenges in FeS Scale Cleanout Operation Overcome using Temporary Isolation, High Pressure Coiled Tubing, and Tailored Fluid Systems
Authors: Buali Mustafa , Ginest Noel , Leal Jairo , Sambo Oscar , Chacon Alejandro , Vielma Jose
Published: February 2021

The carbonate gas producing zones of the Ghawar field have been impacted by extensive FeS scale deposition, reducing overall gas production and significantly increasing risks of well interventions. Previous remediation included the use of workover rigs, which can be costly because of the time necessary for workovers and lost production. H2S levels (2 to 5%) found in the reservoir also contribute to higher costs and risks when using workover rigs.

A chemical solution was also considered, but the FeS could not be 100% dissolved with HCl and the chemical reaction generated large amounts of H2S in addition to existing high levels of H2S in the reservoir. This poses a safety concern with the returns at surface along with potential corrosion of the coiled tubing (CT) and completion. Therefore, the safest and most economical method was deemed to be mechanical descaling with CT.

This paper discusses two wells where mechanical descaling was applied using CT. Each well involved four major challenges that included low reservoir pressure, increased reservoir temperature, horizontal openhole completion, and scale with high specific gravity (3.7 to 4.3). The low reservoir pressure required pay zone isolation to allow for returns to circulate out the heavy scale and to minimize fluid losses to the formation. The fact that the wells had long, openhole sections created another challenge for isolation and cleanout. With a bottomhole temperature (BHT) as high as to 310°F, the operational envelope of temporary chemical packers in combination with loss circulation materials (LCMs) to isolate the openhole section had to be expanded. Following mechanical descaling with CT, the final challenge discussed in this paper is the process to clean out the LCM in the horizontal openhole and bring the well back to maximum gas production using pinpoint stimulation techniques.
Correlation of Shear and Turbulence on Scale Formation and Inhibition
Authors: Graham Gordon M. , Thomson Hunter , Bowering Deborah , Stalker Robert
Published: February 2021

Current scale risk analysis focuses on thermodynamic calculations to determine the risk of scale, ignoring system kinetics and the impact of flow regimes on scale precipitation from mildly oversaturated systems. It is however recognised that flow regimes affect scale precipitation. Surface growth is influenced by mass transport and diffusion which are susceptible to shear stress and turbulence. Little work has been reported which examine these factors under conditions that can be readily tuned to match field production conditions. Scale inhibitor evaluation exercises therefore often rely on conventional low shear/static or laminar flow conditions which have been demonstrated in many papers to be largely inadequate for mildly oversaturated systems.

This work addresses this concept and focuses on scale deposition and growth at metal surfaces as well as bulk (liquid phase) nucleation and growth in mildly oversaturated brines as a function of increasing shear. A series of controlled experiments have been conducted under “mildly oversaturated” conditions to examine the effect of; no shear conventional “static” tests, moderate shear mixed statics and much higher shear regimes including rotating cage and jet impingement approaches with calculated shear stresses up to 500 Pa and higher. This builds on previous work published by the authors in this area1 and further illustrates the importance of conducting tests at field representative shear conditions. Since shear and turbulence have a governing effect on the critical scaling tendency (the level of oversaturation below which brines remain stable under normal production conditions) the ability to correlate between shear and the propensity for scaling in mildly oversaturated systems is critically important in determining the risk of scale at different locations in the production stream.

New test methods have been validated which allow the impact of shear and turbulence to be observed under conditions more representative of production conditions. These methodologies lead to scaling in mildly oversaturated brine systems without having to adjust brine chemistry or otherwise increase the scaling regime, i.e. by adjusting the flow regime to reproduce the shear expected at critical locations in the production system. Improved methodologies are therefore presented which allow more appropriate scale inhibitor qualification, taking into account the impact of shear and turbulence under field representative conditions. The work shows that this is critically important for mildly oversaturated conditions.
An Assay Method for the Detection of all Scale Inhibitors at Extremely low Concentration
Authors: Liu Ya , Kan Amy T. , Yan Chao , Wang Fei , Wang Lu , Tomson Mason B.
Published: February 2021

Accurate detection of scale inhibitors has always been vitally important to monitor scale treatment during oil and gas production. However, there remains an ongoing challenge to analyze scale inhibitors at low concentrations, especially with polymeric scale inhibitors. This paper presents an assay method designed to detect all types of scale inhibitors, especially at low concentrations, and an expert program developed to guide the method. The program guides the preparation of a field brine barite solution at a fixed barite super-saturation. Scale inhibitor concentration is then measured via the method of standard additions, assuming a linear relationship between the scale inhibitor concentration and the logarithm of barite induction time. Seven different scale inhibitors, including phosphonates, carboxylates and sulfonates, were detected in two typical synthetic brines at low concentrations. In addition, this assay method has also been applied to scale inhibitor detection in actual field brines. In general, this easily-implemented method can directly detect the residual level of any scale inhibitors in field brine within the range of about 0.3 – 100 mg/L active. Emphasis in this paper is on low concentrations. Measurement of low concentration scale inhibitors not only help to monitor scaling tendency but also effectively prevent overuse of scale inhibitors and thereby protects the environment and saves money. This is the first method that can detect all scale inhibitors at extremely low concentration. Field applications, strengths, and interferences will be discussed using laboratory and field examples.
Concept, Design and Implementation of a Halite Scale Mitigation Completion in a Gas Well
Authors: Maxwell Doug , Young Keith
Published: February 2021

A North Sea operator was planning to sidetrack an existing gas well to access untapped reserves with an extended reach, sub-horizontal reservoir target. The well was expected to deposit halite scale in the lower part of the completion and across the sandface based on experience from other wells in the field and a production chemistry desk study, possibly from initial production. The project team investigated completion concepts for the well that would address the scaling issue and selected the most appropriate concept prior to designing and planning a practical installation. Several concepts were examined for practical application, including a detailed risk review, before a capillary water delivery system was selected. This involved running 3 capillary lines through the production packer to chemical injection valves deployed on a pre-perforated tailpipe inside the lower completion. As this lower completion was a 5” perforated liner, significant tolerance challenges had to be overcome. The well was completed with the selected concept in January 2013, with the water delivery system injecting 8 bbls of water per day from initial production. The well is on stream and producing at higher than expected rates, with no halite scaling issues identified. By identifying potential flow assurance issues at the concept stage, innovative applications of existing technology can be considered and applied. A multidisciplinary project team is required to meet the demands of such a challenging project. With halite scaling becoming increasingly problematic in the North Sea, the application of water delivery completion concepts may become key to future developments.
Predicted and Observed Evolution of Produced Brine Compositions, and Implications for Scale Management
Authors: Hu Yisheng , Mackay Eric , Ishkov Oleg , Strachan Alistair
Published: February 2021

Produced water was sampled and measured repeatedly during production from an offshore field, and an extensive brine chemistry dataset was developed. Systematic analysis of this dataset enables an in-depth study of brine/brine and brine/rock interactions occurring in the reservoir, with the objective of improving the prediction and management of scale formation, prevention and remediation.

A study of the individual ion trends in the produced brine, using the types of plot developed for the Reacting Ions Toolkit (Ishkov et al., 2009), provides insights into what components are involved in in situ geochemical reactions as the brines are displaced through the reservoir, and how the precipitation and dissolution of minerals and the ion exchange reactions occurring within the reservoir can be identified. This information is then used to better evaluate the scale risk at the production wells.

A thermodynamic prediction model is used to calculate the risk of scale precipitation in a series of individual produced water samples, thus providing an evaluation of the actual scaling risk in these samples, rather than the usual theoretical estimate based on endpoint formation and injection brine compositions, and the erroneous assumption that no reactions in the reservoir impact the produced water composition. Nonetheless, the usual effects of temperature, pressure and brine composition are accounted for in these calculations using classical thermodynamics. The comparison of theoretical and actual results indicates that geochemical reactions taking place in this given reservoir lead to ion depletion that greatly reduces the severity and potential for scale formation. However, ion exchange reactions are also observed, and these too affect the scale risk, and the effectiveness of scale inhibitors in preventing deposition.

Additionally, comprehensive analysis using a geochemical model is used to predict the evolution of the produced brine compositions at the production wells, and to test the assumptions about which in situ reactions are occurring. A good match between the predictions from this geochemical model and the observed produced brine compositions is obtained, suggesting that the key reactions included in the geochemical model are representative of actual field behaviour. This helps to establish confidence that the model can be used as a predictive tool.