bluuebunny/crossref_metadata_2025 huggingface dataset:
Laboratory Assessment of Rock Wettability Effect on Polymer Retention in Carbonates
Authors: Hernández-Morales Álvaro , Mushtaq Muhammad , Sebastian Anoo , W. Al-Shalabi Emad , AlAmeri Waleed
Published: March 2023

Polymer retention is one of the controlling aspects of an effective polymer flooding process. Very few studies discussed the effect of rock wettability on polymer retention, with no consensus on the outcome. While some studies described that oil-wet rocks have low polymer retention, others reported the opposite. This work investigates the effect of rock wettability on the retention of an ATBS-based polymer onto carbonates at high salinity and moderate temperature conditions. In this study, static and dynamic retention tests of an ATBS-based polymer onto high permeable Indiana limestone outcrops were conducted in both absence and presence of oil. These tests were conducted at 50 °C using representative crude oil and formation water (167,114 ppm) of Middle East carbonate reservoir conditions. For the two-phase dynamic tests, the cores were aged at 90 °C for different times (8 hours, 3 and 14 days) to create different wettability conditions, which were verified by Amott index to water. Then, polymer retention and in-situ rheology, including RF and RRF, were determined. Similar procedure was followed for dynamic single-phase tests, but without core aging. Furthermore, single- and two-phase static tests were conducted under identical experimental conditions to compare the retention values.

The results of Amott index to water showed that the selected aging times were suitable for creating different wettability conditions, where cores with longer aging times had a wettability more towards oil-wetting state. It was observed that three-days period of aging was enough to restore the wettability of Indiana limestone outcrops used in this study. Also, polymer dynamic retention was found lower in the presence of oil by about 35 to 47% as opposed to its absence. A further decrease in polymer retention by 14% was obtained for cores with a more oil-wetting condition resulting in a retention level of about 25 µg/g-rock. This is because oil-wet cores have a larger and effective surface area covered by the oil film, leading to a lower surface area left for polymer adsorption as opposed to cores with a wettability towards a more water-wetting state. On the other hand, single- and two-phase static adsorption tests showed non-comparable and very high retention values in the range of 305-337 µg/g-rock. This finding indicates that aging of the rock in such tests does not play a decisive role in obtaining representative polymer retention levels comparable to the dynamic tests. This study is one of the very few works that discuss the effect of rock wettability on polymer retention in carbonates. The study provides an essential insight into the inconclusive results in the literature by highlighting the role of wettability effect on polymer retention based on both static and dynamic retention tests.
Microfluidics for Carbonate Rock IOR: Some Lessons From Fabrication, Operation and Image Analysis
Authors: Duits Michael H.G. , Le-Anh Duy , Ayirala Subhash C. , Alotaibi Mohammed B. , Gardeniers Han , AlYousef Ali A. , Mugele Frieder
Published: March 2023

After successful implementation of Lab-on-a-chip technology in chemical and biomedical applications, the field of petroleum engineering is currently developing microfluidics as a platform to complement traditional core flooding experiments. Potentially microfluidics can offer a fast, efficient and low-cost method to screen many variables like flooding brine composition, reservoir temperature and aging history. We addressed this potential for the waterflooding of carbonate rocks. Using thermostated glass micro- models with rock-inspired ‘dual depth’ pore geometries as a basis, we explored i) introduction of calcite chemistry into the chip, ii) monitoring of changes in fluid composition and iii) quantification the residual oil from visualization. The development aspects of these efforts are the scope of the present paper.

Glass microchannels were functionalized by firmly attaching calcite nanoparticles to the inner surfaces and expanding them via seeded growth. Optical microcopy allowed to monitor the calcite distribution if the particles were not covered with crude oil (CRO). The calcite coating density could be steered, but also showed variability within the chip and between chips. Measurement of residual oil saturation (ROS) from optical microscopy is more challenging in the presence of calcite particles, due to their darker appearance. However, comparing the dynamic intensity of individual pixels with those in CRO- and brine-filled chips, allowed us to not only accommodate the calcite-induced optical differences, but also to find a correlation between calcite coverage and ROS. Our developed data analysis scheme, based on mask overlaying and image registration, also allows a sensitive monitoring of ROS, for both short (30 s) and long times (8 days) using low (2X) magnification Additionally captured high-resolution (10X) images reveal vital details underlying the global oil displacement. Implementation of more on-chip characterization tools could significantly contribute to a better mechanistic understanding of the IOR process. Non-invasive add-ons like Raman microscopy or chemically inert dyes could be implemented directly. Incorporation of electrode sensors will only be efficient if the chips can be re-used, which is currently not the case. This paper uses results from published works and unpublished data to reflect on the development of the microfluidics-for- testing IOR technologies. Our identification of possibilities and technical challenges in IOR on calcite- coated chips should be helpful in future designs of microfluidic research studies.
Real-Time Borehole Breakout Identification Utilizing Ultrasonic Amplitude Images in a Slim Borehole
Authors: Al Zayer Mohammed , Solial Ali , Taher Ahmed , Al Maimani Ali
Published: March 2023

Wellbore deterioration and breakouts can be mitigated by following proper drilling practices and drilling fluid optimization techniques. While conventional LWD tools can help in identifying borehole breakouts, advanced ultrasonic amplitude images can be utilized to identify borehole breakout intervals and additionally determine their widths to enable safe mitigating actions while drilling. Ultrasonic amplitude images depend on impedance contrast to reliably identify borehole shape and features.

Breakout identification depends on the contrast in properties between the formation and the mud, and historically density and photoelectric images have been used for this purpose. Using ultrasonic imaging tools, breakout can be identified using azimuthal variations in measured amplitude. The ultrasonic imager can be used to determine the orientation of breakout intervals with improved resolution compared to conventional tools, and the image can be transmitted to surface through mud-pulse telemetry. Pre-planning is critical to optimize the tool settings, including the firing voltage and frequency.

Pre-well modelling combined with real-time data is critical for drilling the well safely, and a pre-well geomechanics study provided an optimum mud-weight window based on offset-well analysis. The ultrasonic imager provided high-definition images for mud-weight optimization and gave insight into breakout width and direction in real time. In combination with other real-time measurements, the image was utilized to help stabilize the borehole and avoid hole deterioration by identifying the zones experiencing extensive wellbore damage. Time-lapse analysis provided critical information for understanding how such deterioration developed over time.

This is the first application of amplitude images in a slim borehole for real-time geomechanics. The data helped with optimizing the mud weight and provided critical information for optimizing the completion design and anticipating problematic intervals. The acquired data was further utilized to study the effectiveness of pumped bridging material and together with time-lapse data will provide critical information to improve future wells in similar environments.
First Application in Oman of New Single Stage Retarded Sandstone Matrix Acidizing
Authors: Qassabi Hajir , Rafliansyah Andika Putra , Falla Johnny , Al-Yaaribi Ahmed , Al-Ruzeiqi Saleh
Published: March 2023

The objective of matrix acidizing in sandstone reservoirs using acid systems that contains Hydrofluoric acid (HF) is to widen the pore throats and spaces in order to increase the permeability around the wellbore and remove formation damage. One major disadvantage of this acid system is the secondary and tertiary reactions, which may lead to precipitations that damage the formation. Because of this, pumping sufficient pre-flush and post-flush volumes of Hydrochloric acid (HCl) is critical to prevent such damaging reactions. However, the placement of such fluids still is a concern in multiple opened layers or long open intervals zones.

Stimulating sandstone reservoirs in the Southern fields of the Sultanate of Oman is very challenging, especially in those that exhibit relatively low permeability. These formations, based on petrology work, contains significant amounts of clays and feldspars, which make it difficult in the designing process of the acid formulation. A new version of HF acid system was recently developed. It is specially formulated, so it does not require the addition of Hydrochloric acid (HCl) pre-flush. Because of this, it can be pumped as a Single Stage Retarded Acid System. In addition, its higher reactivity allows deeper penetration, and it has the ability to minimize secondary reactions and damaging precipitates.

Lab testing work was conducted to ensure the effectiveness of this Single Stage Retarded Acid System. The results were promising as they show a good improvement in the rock permeability. These results were encouraging to carry field trials in the sandstone reservoirs in Oman Southern fields. Up to now, it has been pumped in sandstones for oil producer wells and for water injector wells. The actual treatment using this system showed increased oil productivity by higher than 60% as well it shows higher than 80% in water injectivity.

This paper presents the testing, designing and pumping the SSRAS (Single Stage Retarded Acid System), as well as the comparison with the conventional HF acid system in Southern fields of Oman. It outlines the laboratory work and analysis done as well as the field trials.
Downhole Estimation of Relative Permeability using Dynamic Formation Testers: A Novel Approach to Reduce the Uncertainty in Reservoir Modelling Study
Authors: Kumar Saket , Joshi Parth , Bajpai Prakash , Aggarwal Akshay
Published: March 2023

The reservoir fluid flow is characterized by relative permeability data, whose measurements are conventionally made in the laboratory on the cores acquired downhole of different rock types. The major drawback of such conventional core (SCAL) studies is their inability to capture the native wettability and in-situ reservoir fluid flow characteristics. Moreover, this lab based relative permeability data is sometimes unavailable, which requires one to estimate the relative permeability curves based on understanding of the reservoir or public literature and further tune the curves to match the actual pressure and production history of the reservoir during dynamic modelling. This process also incurs additional cost and requires additional time and efforts. Hence, an attempt has been made in this study to develop a novel workflow to estimate the relative permeability curves downhole using formation testers. This new method for interpreting relative permeability curves will complement the already existing conventional methods like SCAL and can also be used directly in the absences of lab data.

In this approach, the Single Probe (PS), Pump Out (PO), and Fluid Analyzer (FA) modules of the Modular Formation Dynamic Tester (MDT) tool were assembled and set at the desired depth. Subsequently, the PO module was used to draw out the fluids from the formation and aid in recording the production and pressure drawdown data. The relative permeability of both oil and water phases were estimated at endpoint saturation using steady state approach, and the JBN method was applied after breakthrough and during transition phase using the displacement data (production and pressure data). The advanced well logs were used to interpret the other reservoir properties like porosity, permeability, and etc.
An Analytical Model for Pressure Transient Behavior of Acid-Fractured Well in Fracture-Cave Oil Reservoir: A Field Example from Tarim Basin in China
Authors: Ai Shuang , Pang Wei , Du Juan , Liu Mike , Tabish Haider Syed
Published: March 2023

In fracture-cavity carbonate reservoirs, caves and fractures are the basic storage space. The SN oil and gas field in the Tarim Basin is one of this special fracture-cave oil reservoir. The main storage and seepage space are large caves and large fractures, and the pore space is large, which can reach above the meter level. It is very difficult to interpret this kind of oil reservoirs by the conventional triple medium well testing method. It is of practical significance to establish a well testing interpretation model for cave-type reservoirs and to interpret the well testing data of such reservoirs. Based on the typical well-fracture-cave configuration, we consider the finite conductivity of acid fracturing fractures. The fracture zone is regarded as a linear formation with finite conductivity and volume. Due to cavity characteristics of the cave, it is regarded as an equipotential media, and the internal pressure is equal in the all volume, and the cave supplies fluid to the outside in the form of storage flow. By coupling the acid-fracture flow, the flow in the fracture zone and the cave flow, two mathematical models for well test of acid fracturing in carbonate reservoirs are set up. Practical solutions of bottomhole pressure are obtained by using Laplace transform and Stehfest numerical inversion algorithm. The research results show that there are six or seven flow regimes exhibited: acid-fracture linear flow, with or without fracture zone storage flow, linear flow in fracture zone, cave storage flow, linear flow in fracture zone, cave storage flow, boundary flow. The distance between the acid-fracture and the cave affects the duration of the linear flow in the fracture zone. The greater the conductivity of the fractured zone, the more the linear flow of the fracture, the smaller the conductivity, the greater the seepage resistance, and the linear flow is converted into the reservoir flow of the fracture. Finally, a field example was explained by using the double logarithmic curve chart of the drilled cave model, and several parameters including acid-fracture, cave and the fractured zone were obtained by inversion. The production simulated based on the inversion results are in good agreement with the actual values. This paper presents two practical models to interpret the transient pressure responses of acid-fractured well in fracture-cave reservoir. The flow behavior is firstly investigated and the field example demonstrated practical use of the model to obtain the key parameters of acid-fracture, fracture zone and the cave.
Preparation and Properties Investigation on Sand-Polyacrylamide Composites with Engineered Interfaces for Water Shutoff Applications
Authors: Almohsin Ayman , Krishnan Mohan Raj , Alsharaeh Edreese , Harbi Bader
Published: March 2023

Herein, we report a facile preparation and characterization of polyacrylamide (PAM)-2D nanofiller (commercial graphene (CG) and hexagonal boron nitride nanosheets (h-BN)) composite hydrogel coated sand for water shutoff application. To prepare the sample, 4 wt% of aqueous PAM solution that is mixed with organic cross-linkers of hydroquinone (HQ) and hexamethylenetetramine (HMT) in 1:1 weight ratio, aqueous potassium chloride (KCl) solution and a specific amount of CG or h-BN. A specific amount of the above solution is added to sand and well mixed and subsequently cured at 150 °C for 8 hours. The prepared sand-polymer composites were characterized by Fourier-transform infrared spectroscopy (FT-IR) for chemical composition, X-ray diffraction (XRD) for successful polymer coating onto the sand, thermogravimetric analysis (TGA), and differential scanning calorimetry (DSC) for thermal stabilities. the success of the sand coating was evaluated based on the peak intensities depicted for the sand-PAM gels with respect to neat-sand and neat-PAM. The absence of some of the peaks and their corresponding decrease in the intensities indicates the successful coating of the PAM hydrogel matrix onto the sand surface. The thermal stability of the sand samples has reached as high as 190.7 °C. The prepared material has a high potential for water shutoff applications.
Well Productivity Optimisation with Tailored Hole Spacing in Smart Liners
Authors: Mogensen Kristian
Published: March 2023

Optimum productivity from long horizontal wells requires effective stimulation. The Smart Liner lower completion addresses shortcomings of other matrix-acid stimulation techniques in regards to acid placement along the reservoir section. The concept relies on a limited number of small holes (orifices) drilled through the liner itself to distribute acid over the entire drain length. Different hole spacings can yield similar flow distributions but may result in different stimulation efficiencies. What is best, a few deep wormholes with acid washing in between, or many, less penetrating but closer wormholes? The objective of this work is to investigate which parameters influence the optimum hole spacing leading to the most improved overall reservoir contact.

We derive a radial wormhole growth model as a function of time and initial jet velocity, which honors the observation that incremental penetration depth tapers off versus time. This model is specifically tailored to account for the substantial jet velocities generated by the limited-entry liner completion, often in the range of 15-50 m/s, occasionally higher. It qualitatively matches field observations showing that the maximum required acid coverage often lies in the range 0.4-0.5 bbl/ft. Exceptions to this trend have been observed and they deserve further investigation. The hole spacing generally increases with well length to ensure sufficient jetting towards the toe of the well.

Work is ongoing to convert the number and length of all wormholes combined to an average overall injectivity improvement for the well. This effort will lead to a more qualitative match to the real-time stimulation data. Field data suggest that the typical transient injectivity is improved by a factor 2-3, sometimes more, if the initial skin prior to stimulation is very high. Larger improvements have been observed during stimulation of dolomite rocks with 28 wt% HCl, possibly due to more drilling-induced damage.
Innovative Approach to Identify PVT Regions in a Sandstone Reservoir in Khafji Field with Geological Events
Authors: Al-Qenae Khaled , Al-Otaibi Mohammed , Belazreg Lazreg , Akhtar Mohammad
Published: March 2023

Prior to initiating a reservoir simulation study, the readiness of a complete set of fluid analysis data should be assured and quality checked. This usually includes, but not limited to, identification of any vertical and lateral variation of reservoir fluid properties. Identification of these trends can have tremendous impact on the results of the reservoir simulation project.

Recently, a reservoir simulation study was conducted on a brown reservoir in a Middle Eastern field. This reservoir is geologically characterized by various faults which were developed after fluid migration. The presence of these faults has resulted in communicated reservoir compartments. Application of traditional workflow in analyzing the PVT data was insufficient to identify any trend in the fluid properties or account for any vertical and lateral differences in reservoir fluid properties.

This paper explains the work done to characterize fluid properties for a structurally complex sandstone reservoir, where most of the downhole fluid samples were collected in the 1960s. Unfortunately, the sampling depth was not reported for most of the samples at that time, with no production logging data available to identify the production zones within the large perforation interval. Laboratory measurements indicate under-saturated oil with variation that could be correlated with depth. Samples were obtained from three geological subzones; Layers-1, 2 and 3, where a shale layer is believed to be partially separating Layer 1 from the other layers. Part of the challenge is that a large number of samples were collected from different sublayers as a combination, which increases sampling depth uncertainty.

Defining properties trend versus depth was the main challenge in the study. This uncertainty was addressed by developing an iterative "what-if?" analysis scenarios by integrating geological parameters. A new model was prepared that considered the initial conditions of the reservoir fluid before any migration or tectonic activities took place. Applying the proposed approach, resulted in a clear trend of hydrocarbon properties variation with depth and provided a clear observation of the presence of one PVT region in the reservoir. Based on the results of this study, one PVT region with a solution gas-oil ratio trend versus depth was applied into the reservoir model, which resulted in a reliable dynamic simulation model.
Assessing Geological Deformation Using Distributed Fiber Optic Sensing
Authors: Busetti Seth , Kazei Vladimir , Merry Harold
Published: March 2023

This work presents a conceptual framework for assessing geological deformation using distributed fiber optic sensing that is applicable to several common sources of strain encountered during the reservoir lifecycle. Common applications include strain associated with seismic and aseismic fault motion, natural and hydraulic fracture dilation and closure, as well as poro-elastic strain evolution during injection and production. We briefly review the main fiber-based techniques for recording geological sources of strain and highlight key deformation characteristics at different spatial and temporal resolutions. The relationships between common acquisition parameters such as spatial resolution, data sampling rate, ability to measure relative and absolute strain, and a priori knowledge of geological strain including the availability of baseline measurements are discussed. A few examples are shown from experimental studies at the Houston Aramco Research Center. Using these insights as a conceptual framework for assessing geological deformation leads to more informed decisions when planning distributed fiber optic sensing acquisitions and interpreting associated strain data.
New Horizon for Downhole Scale Management Towards Sustained Well Production
Authors: Almajid Hussain , Thwaiqib Ibrahim , Ribeiro Carlos , Alghamdi Khuloud
Published: March 2023

Iron sulfide scales is considered one of the most commonly encountered formation scale in the oil and gas industry which can adversely impact well deliverability and integrity. Traditional chemical treatments using inorganic acids such as HCl are not favorable due to its corrosive nature and rapid generation of H2S gas. The success rate for such operation is further challenged by the molar ratio of iron to sulfur and the existing polymorph of iron sulfide such as pyrite, pyrrhotite, troilite, marcasite and mackinawite.

This paper aims to share the laboratory development and field application results for a revolutionary chemistry that was developed as an integrated solution to dissolute iron sulfide scales and inhibit further scale nucleation. Extensive laboratory testing was conducted under anaerobic conditions to create an evolved chelating agent with high iron sulfide dissolution, minimal corrosion rate and no H2S generation. The experimental setup included in-situ mixing of Fe(+2) and S(-2) to create iron sulfide scale that were placed in glass vial reactors and exposed to specific temperature and pressure. Furthermore, a thorough evaluation of sulfide scale properties and behavior under varying reservoir pressure and temperature is incorporated into a computational model to understand and accurately control the scale deposition process.

Several cleanout jobs have been successfully performed in the field using this treatment. Lab results showed minimal presence for the ferrous ion and total sulfide once filtered from the aqueous phase. Furthermore, the results for iron sulfide dissolution at different pH levels will be shared to determine the optimum pH values for the chelating agents. The collected data showed that this dissolver was able to outperform THPS based dissolvers without the adverse effects of HCl. Post job results will be discussed in this paper including job design, field execution, lessons learned and solid compositional analysis. Furthermore, inhibition program has been implemented based on the acquired results from this model and frequent inspection conducted showed no scale deposition over extended production periods.

The novelty of this approach is its ability to efficiently remove iron sulfide scales and inhibit nucleation at early stages without relying on inorganic acids. Lab results will be discussed in detail to examine the role of chelating agents in iron sulfide dissolution at different pH levels under anaerobic conditions. Field deployment data will be shared to definitively prove the effectiveness of this treatment in removing and preventing further iron sulfide precipitation. This study will help shed some light on an issue that has long concerned the oil & gas industry and up to this date no effective prevention mechanism has been discovered.
CO2 Mineral Trapping Potential of Carbonates: A Numerical Investigation
Authors: Mouallem Johny , Fathy Ahmed , Arif Muhammad , Mahmoud Mohamed
Published: March 2023

During CO2 geo-storage, mineral dissolution is considered as the safest trapping technique however it is the longest and the most complicated trapping mechanism involving geo-chemical reactions and physical forces like diffusion and advection. Many factors also influence the mineral trapping capacity of the geological formation e.g., mineralogy, temperature, pH, CO2 fugacity, pressure of CO2, salinity and composition of the brine.

The scope of this study is to investigate the mineral trapping of CO2 in Arabian carbonates reservoirs as a function of temperature, brine composition and pH of the subsurface systems. Numerical simulations are performed using the multi-phase simulator GEM-CMG. 2D and 3D models are developed to examine the mechanisms occurring during mineral trapping and how these affect its efficiency. The mineralogy of a carbonate field from an Arabian formation is used. Sensitivity analysis has been performed on the effect of temperature, pH and brine composition on CO2 mineralization tendency and porosity.

The results suggest that dissolution and precipitation of minerals occurred during and post CO2 injection while pH had the major influence on mineral trapping. At basic pH conditions, pH=9, the highest amount of CO2 was mineralized while at mid pH, precipitation of carbonates decreased remarkably. Changing the brine composition also highly affected the storage capacity e.g., divalent salt accelerated CO2 mineralization. Moreover, temperature tends to promote the mineral activity during CO2 storage.

While a score of publications investigated CO2 storage via structural, residual and dissolution trapping mechanisms, still the mineral trapping potential and its influencing factors have not been investigated much. This paper thus provides new insights into CO2 sequestration by mineral trapping pertinent to Arabian carbonate rocks.
Global First 18.625 and 13.375-in Level-2 Casing-While-Drilling Successful Deployment through Open-Hole and Cased-Hole Sidetracked Wellbores to Isolate Severe Unstable Zones
Authors: Almasmoom Salahaldeen S , Refai Ahmed , Al-Qahtani Faris A , Stonestreet David B
Published: March 2023

During non-productive time (NPT) such as stuck pipe incidents, reducing the operational time and associated cost of the trouble mitigation should always be the goal. Therefore, the engineering team searched for new and innovative ways to reduce the NPT when stuck pipe incidents happen, and successfully utilized an existing technology in a new way not yet performed on a global basis.

In seldom incidents drilling or tripping through unstable zones (especially when drilling through sticky shales and loose sandstone zones charged with downhole faults/fractures) with complete loss of circulation, severe tight spots, stalling tendencies, hard backreaming, etc. might be experienced. In the worst case, the pipe might get stuck and cannot be freed. The engineering team investigated several options to allow drilling and casing off the trouble zones in such incidents, while reducing the NPT in the same time. Sidetracking through open-hole and/or cased-hole whipstock, then utilizing level-2 casing-while-drilling technology to drill and case-off the instable zones was the best cost effectient option.

Successful deployment of level-2 16-in × 13-⅜-in casing-while-drilling (CwD) technology through an 18-⅝-in cased-hole sidetrack whipstock and level-2 22-in × 18-⅝-in CwD technology through open-hole sidetrack led to drilling and casing off severe unstable sections in two separate wells in different areas of interest. The level-2 13-⅜-in CwD utilization to drill and case-off trouble zones through cased-hole sidetrack was the global first. The level-2 18-⅝-in CwD utilization to drill and case-off trouble zones through open-hole sidetrack was the country first. Both led to significantly reducing the non-productive time (NPT) resulted from the stuck pipe incidents in a cost effective manner. Extensive engineering simulations, technical limits, and risks assessment were set to insure flawless execution. During the job execution, the drilling performances were constantly monitored. The engineering simulations are updated using the actual parameters to ensure accurate measurements of the accumulated fatigue while being rotated to preserve the casing due to exposure to high dogleg severity (DLS) in the sidetracked wellbore. Furthermore, the hydraulics are optimized real-time to ensure hole cleaning without further increase in the equivalent circulating density.

Even with no prior global experience of the utilization of this technology through such operation, the pursuit of the technical limit was to reduce the NPT as much as possible. The technical paper will highlight the planning steps, challenges, detailed engineering simulation, risks mitigations and engineered solutions, and the successful results of the deployment of level-2 CwD runs through sidetracked wellbores.
Locating CO2 Leakage in Subsurface Traps Using Bayesian Inversion and Deep Learning
Authors: Zhang Zhen , He Xupeng , Li Yiteng , AlSinan Marwa , Kwak Hyung , Hoteit Hussein
Published: March 2023

Geologic CO2 sequestration (GCS) is a promising engineering measure to reduce global greenhouse emissions. However, accurate detection of CO2 leakage locations from underground traps remains a challenging problem. This study proposes a workflow that combines Bayesian inversion and deep learning algorithms to detect the sites of CO2 leakage. There are four main steps in the workflow. Step 1: we identify the key uncertainty parameters. Here we mean the CO2 leakage location. Then we get the training set using Latin Hypercube Sampling (LHS) method and perform the high-fidelity simulation using CMG. Step 2: we train the surrogate model using the data set collected from the last step, in which the Bayesian optimization is used to tune the hyperparameters automatically. Step 3: we perform the Bayesian inversion to invert the CO2 leakage location, in which the surrogate serves as the forward model to reduce the computational expense. Step 4: we feed the inverted CO2 leakage location into the high-fidelity model to produce the pressure response. If the error between the pressure response between the surrogate and the high-fidelity model is small enough, the solution is accepted. Otherwise, the accuracy of the surrogate model and the convergence of the Bayesian inversion process are revisited. We validate this method using a synthetic model of CO2 injection. Results show that the proposed Bayesian inversion assisted by the deep learning algorithm can accurately detect the CO2 leakage location with narrow uncertainties. This approach provides an accurate and efficient way to detect CO2 leakage locations in real-time applications.
Tailored Engineering Cementing Solution to Maintain Well Integrity in Shallowest Liner for Underground Gas Storage Project - Case History from Southwest China
Authors: Li Fangfang , Bhaisora Devesh , Yue Huang
Published: March 2023

Underground gas storage (UGS) wells have emerged as a strategic solution in China. Success of UGS projects largely depends upon maintaining long term well integrity. Cement slurries that are placed across a wellbore should exhibit superior cement bonding as evidenced through a cement bond log (CBL) and long-term integrity to sustain the cyclic stress change by the injection and production process. Such slurries should have improved mechanical properties and the job execution should follow all cementing best practices.

The well architecture included a 9 5/8-in. surface casing and a 7-in. production liner. The 7-in. Liner was run inside an 8.5-in. open hole and extended to surface using a tie-back liner. This well architecture should have a superior quality of cement across the entire liner. Multiple Finite Element Analysis (FEA) runs were performed to determine an optimum Young's modulus and Poisson Ratio for the cement slurry. These rigorous tests can take weeks to complete. As the well was shallow, to cover a wide range of well profiles, three different slurries were tested prior to the job.

The initial mud weight planned for the well was in the range of 1.25 g/cm3 to 1.4 g/cm3. Due to gas influx, the mud density in the section was increased to 1.90 g/cm3. However, losses were also encountered at this mud density. Hydraulic modelling was revised, and slurry rheology and pumping rates were optimized to ensure equivalent circulation density (ECD) control within the pore pressure and fracture gradient window. Displacement rates were optimized to facilitate good displacement efficiency for hole cleaning. The slurry design was tailored with special additives to provide a synergetic effect of improving mechanical properties and minimizing seepage losses. Multiple computational fluid dynamics (CFD) runs were performed to evaluate the cementing job quality and based on the simulations it was decided to increase the cement volume to minimize any impact of contamination. The cementing job was performed with no operational issues and cement returns were observed above the top of the liner. Two different cement evaluation logs - CBL and ultra-sonic log, were conducted and showed good cement quality in the open hole section, meeting the well objectives.

With this successful implementation, the tailored engineered cementing solution was highly recognized. The design and execution methodology were highlighted as the guideline for further successful cementing operations in UGS projects. This study shows a fully comprehensive and scientific way to improve cementing quality for long-term well integrity for UGS projects.
The Impact of Salt Ions on the Rheology of a Crosslinked Polymer Containing a Chelating Agent
Authors: Othman Amro , Murtaza Mobeen , Aljawad Murtada , Kamal Muhammad , Mahmoud Mohamed , Kalgaonkar Rajendra
Published: March 2023

The growth in hydraulic fracturing activities increased the demand for freshwater, a scarce commodity in water-deprived regions. The alternative is to utilize seawater (SW) or produced water (PW) from oil and gas operations to formulate high total dissolved solids (TDS) fracturing fluids. If achieved, it will result in more sustainable hydraulic fracturing operations that are cost and logistics efficient. Furthermore, aside from the hydrocarbons in PW, both SW and PW have similar ions, so the same remedy should be suitable for both. Therefore, this study investigates the influence of individual ions on a crosslinked polymer solution that contains a chelating agent.

The study investigated the effect of individual ions on the rheology of fracturing fluid formulated using carboxy methyl hydroxy propyl guar (CMHPG) polymer. The studied salts included calcium chloride (CaCl2.2H2O), magnesium chloride (MgCl2.6H2O), sodium chloride (NaCl), and sodium sulfate (Na2SO4). First, the effect of delayed zirconium (Zr) crosslinker on individual ions was investigated by varying the Zr concentrations (0.3, 0.6, and 1 wt. %). Then, the selected crosslinker concentration was used to inspect the impact of N, N-Dicarboxymethyl glutamic acid (GLDA) chelating agent on the crosslinked system at different concentrations (4, 10, and 20 wt. %). Finally, the rheology of polymer in SW and deionized water (DW) was tested as a reference. The testing parameters on the two sets of the experiments were constant, which included 70 °C temperature, 500 psi pressure, 100 1/s shear rate, and 45 minutes for polymer hydration in a fluid.

The rheology of the crosslinked CMHPG polymer was mostly impacted by sulfate and then calcium ions. The viscosity of the solution containing only sodium sulfate was reduced to that of SW. Unlike the DW, the increase in the crosslinker concentration increased the viscosity of SW and individual ion solutions. The ions’ salinity affected the long-term viscosities as they dropped to less than 10 cP in all concentrations in less than one hour. Sodium and magnesium ions did not significantly impact the solution viscosity and behaved like that of DW. The low-concentration chelating agent raised the stability of MgCl and DI solutions. In the SW, NaCl, and CaCl2, the viscosity dropped at the first 20 minutes then the curve rose to reach higher values than the DI after 3 hours.

This work demonstrated how the crosslinker and chelating agent affect different salt systems’ behavior and viscosity. The results can be used to understand the rheology of fracturing fluids based on seawater or produced water.
Unique Solution to a Challenging Multilateral Well Intervention Using an Electric Multilateral Tool and Distributed Temperature Diagnostics on Coiled Tubing in a West Kuwait Field
Authors: Sebea Salem Hamad Al , Abu-Eidah Abdullah Ibrahim , Patra Milan , ALKhayouti Malak Yousef , Bumijdad Mohammed Mousa , Al-Hamdan Abdulaziz , Khandelwal Nakul , Chawla Sapna , AlWazzan Abdulatif , Alkreebani Mohammad , Travesso Joshua
Published: March 2023

Multilateral wells offer multiple benefits to oil and gas operators, including lowering the field development cost by minimizing wellsite construction work and increasing reservoir contact leading to enhanced reservoir production. They also present challenges, with each leg requiring separate intervention and uniform stimulation to gain full advantage of these complex wells.

An operator in Kuwait drilled a 2-leg level 1 multilateral well to enhance production from the Mishref formation. Mishref is a fast-depleting reservoir requiring an extended contact area to drain the reservoir uniformly and efficiently. The main challenges with multilateral intervention include identifying the junction depths, gaining lateral entry, and confirming the correct lateral entry. To overcome these challenges, the operator identified the unique technology of utilizing Real-Time Hybrid Coiled Tubing (RTHCT) with an Electric Multilateral Tool (EMLT). Diagnostics using Distributed Temperature Sensing (DTS) were also used to compare pre and post-stimulation effectiveness.

Intervention into a level 1 multilateral well presented several challenges, and RTHCT with the EMLT were successfully used to overcome these. The solution includes a hybrid fiber optic and electrical cable installed in the CT string and a Modular Bottom Hole Assembly (MBHA) equipped with various sensors. An electrically controlled indexing tool, inclination sensor, tool-face sensor, downhole camera, hydraulic knuckle joint, and pulsating stimulation tool were used as part of the BHA to enable real-time diagnostics and dynamic controls from the surface to successfully enter and stimulate both the lateral legs. This customized solution helped identify each different lateral without the need to tag the bottom of each lateral. This paper focuses on applications, strategies, and benefits of specific tool configurations developed for multilateral well intervention, which enabled the stimulation of both the Mishref laterals. Also discussed are the DTS diagnostics used to identify any thief and impermeable zones. Pre and post-stimulation diagnostics were performed to identify the effectiveness of the stimulation treatment.

This paper includes strategies that address proper tool selection, confirmation of lateral entry, hydrostatic pressure balance, borehole stability, and acid design. It also explores the potential of new, synergistic strategies and work processes planned for stimulation of the Mishref reservoir.
Bahrain LNG Import Terminal (BLNGIT) Project:1st LNG Commissioning Cargo and Integration of Imported Regasified LNG (RLNG) with Domestic Khuff Gas in the Existing Distribution Network
Authors: AlKhunaizi Fawaz A. Aziz , Prudhvi Muni Shankar , Mohamed Anwar
Published: March 2023

In order to meet the country's future energy requirements, and in particular the increased demand for electricity and water in addition to major industrial growth, Bahrain's Ministry of Oil & Environment (MoOE) – formerly known as the National Oil and Gas Authority (NOGA) - has taken the strategic decision to import Liquefied Natural Gas (LNG) to supplement existing local gas supplies as a long-term energy policy.

NOGA and the Oil and Gas Holding Company B.S.C (c) (nogaholding) signed project agreements in 2015 for the development of an LNG Receiving and Regasification Terminal in the Kingdom of Bahrain with an international consortium.

The purpose of this paper is to shed light on this ‘first-of-its-kind’ project development in the Kingdom of Bahrain in order to highlight (i) the challenges and management of such challenges, (ii) the ultimate project/operational objectives and successful results, and (iii) lessons learnt.
Modeling Two-Phase Intermittent/Annular Flow Pattern Transition in High Liquid Viscosity Upward Vertical Wells
Authors: Al-Safran Eissa , Ghasemi Mohammad
Published: March 2023

Two-phase flow pattern prediction is required for accurate prediction of liquid holdup and pressure gradient in upward vertical wells. Recent studies of flow pattern models evaluation in high liquid viscosity two-phase in vertical pipe upward flow revealed (Al-Safran et al., 2020) discrepancies in all transition boundaries, including the intermittent (IN)/annular (AN) transition. This study aims to investigate the effect of liquid viscosity to improve Taitel et al. (1980) and Barnea (1987) IN/AN flow pattern transition models predictions. Taitel et al. liquid droplet fallback model is modified by incorporating liquid viscosity effect in the critical Weber number to predict droplet terminal velocity. In addition, this work eliminates the assumption of negligible annular film thickness (due to high viscosity liquid) in predicting the critical gas velocity to transport liquid drop upward, i.e. transition to intermittent flow. Sensitivity analysis revealed that the interfacial friction factor (fi) and liquid entrainment (fE) closure relationships are crucial in Barnea (1987) film bridging and film instability IN/AN transition models. Therefore, a comprehensive evaluation of fi and fE correlations and their combinations revealed that the combination of Pan and Hanratty (2002) fE correlation and Ishii and Grolmes (1975) fi correlation is the best, i.e. produces least prediction error, for wide range of liquid viscosity. A validation study against large experimental database of high liquid viscosity (4 mPa.s to 1600 mPa.s) flow pattern showed high prediction efficiency for the improved Taitel et al. and Barnea IN/AN transition models.
Asphaltene Testing for Inhibitor Evaluation
Authors: Jennings David , Golchha Abhishek , Breitigam Justin , Yen Andrew , Xu Kui
Published: March 2023

Asphaltenes are a global flow assurance problem responsible for reduced production and increased operating costs in many oilfields. Asphaltene inhibitor programs are needed to manage problems and increase operational profitability. Improvements are needed in both developing new inhibitors with better performance and in the understanding and application of testing methods used for evaluating inhibitors.

This paper discusses ongoing efforts to improve our understanding of asphaltene deposition and inhibitor testing with a goal to be able to correlate testing results to satisfactorily predict asphaltene inhibitor field performance before application. Three different asphaltene test methods used in our laboratory are presented. The methods include both live and dead crude oil testing. Results from testing with each method and their relevance to field conditions are discussed. More focus is given on the dead-oil testing methods though as live-fluid testing, being more difficult and costly, is not an option for many field studies. Fundamental deposition studies are shown from one of these methods, highlighting the effect of varying different test conditions on deposition. Finally, a case history of a successful asphaltene inhibitor field application is included at the end of the paper. It is included to provide an example of the benefits of an effective asphaltene inhibitor application and show some comparisons between laboratory testing and field experience.
Extended Well Testing Campaign in Extreme H2S Environment in SIMOP
Authors: Katamesh Hesham , Hamdy Emad
Published: March 2023

In a modern era of unprecedented events, such as the COVID-19 pandemic, energy matters now more than ever. What was previously impossible is now a challenge that should be met with measured risk and a mitigation plan.

In early 2020, a service company pursued a solution to provide a compact surface well test (SWT) package for an extended well test (EWT) on an offshore production platform in the Zafaraana field with extremely high concentrations of H2S. The solution involved proper treatment and safe delivery of well effluent within acceptable H2S limits to a floating production storage and offloading (FPSO) facility.

The EWT was to be installed for a long period to allow production from the reservoir, treatment of the effluent using H2S scavenger, and delivery to the FPSO facility by means of electric transfer pumps. This was the only way to produce because the FPSO facility could not accommodate the high H2S concentrations from the reservoir.

A further challenge was that it was a simultaneous operation (SIMOPs) wherein the rig was engaged in drilling and completion activities of other wells on the same offshore platform; operational conflicts were identified during the HAZOP/HAZID meeting to help mitigate potential issues.