bluuebunny/crossref_metadata_2025 huggingface dataset:
Polymer Solution Preparation and Quality Control at Milne Point
Authors: Aitkulov Almas , Redwine Connor , Alvord Jeremy , Edwards Reid , Seright R. S.
Published: April 2024

This paper focuses on solution preparation and quality control activities associated with the Milne Point polymer flood on the North Slope of Alaska. This project uses ten different polymer injection locations with a variety of skid types and configurations, which had a notable impact on polymer quality control and dissolution operations. Compared with bulk 500-750-kg polymer bags, silos greatly improved the storage capacity and increased the overall quality of polymer wetting in system. Silos also required less physical effort when transferring polymer. Polymer hydration skids that were made inhouse by the polymer supplier were more reliable and experienced fewer polymer solution quality and startup issues than those that were outsourced. These inhouse skids also used a uniform programming software that made it relatively easy to train the operators on new hydration skids. For pumping polymer mother solution, triplex pumps provided the best run time and were most maintenance-friendly, compared with diaphragm or triple screw pumps. Although polymer solutions could be prepared that met our target viscosities without using a nitrogen blanket, corrosion and iron particulates raised substantial reliability and injectivity concerns if nitrogen blanketing was not used—especially when using black iron piping and when the make-up water contained dissolved iron. Inline static mixers were ineffective in mixing mother solution with dilution water when the mixing occurred close to the wellhead. Mixing the two streams too close to the wellhead led to substantial variations in wellhead viscosity measurements. Dedicating individual pumps for injection into a given well provided desirable flexibility in controlling rates and concentrations of polymer for the well. Monitoring produced salinity and polymer concentration provided useful insights about improved sweep and polymer retention associated with the polymer flood. The observed field behavior was consistent with laboratory studies indicating a "tailing" phenomenon associated with polymer retention at Milne Point.
Deploying Polymer Flood in a Secondary Recovery Mode using Horizontal Injectors in a Complex Heavy Oil Field in the South of the Sultanate of Oman
Authors: Al Yaaribi Z. H. , Al Sulaimani H. , Karpan V.
Published: April 2024

Over the past decade, Petroleum Development Oman (PDO) has accumulated significant experience studying and applying polymer flooding under various oil reservoirs and field conditions. In addition to ongoing commercial polymer flooding in the Marmul oil field, the company is actively pursuing polymer projects in more complex and mature oil fields. To accelerate the deployment of these projects, PDO capitalizes on in-house, regional, and worldwide experience. This paper discusses the implementation of polymer flooding in Thayfut a heavy oil field (oil viscosity above 600 cP) in a complex Gharif formation with a thin oil column. The field is produced under the depletion mode with the pressure support supplied by the aquifer. Due to the significant mobility contrast between viscous oil and water, the production water cut has increased significantly, limiting the oil recovery. Polymer flooding with horizontal injectors (parallel to existing horizontal producers) was proposed to achieve higher oil recovery at lower greenhouse gas (GHG) emission intensity. Additionally, this paper describes the development concept, reservoir modeling, and forecasting details. The scope of surface development is also discussed regarding water supply options, polymer facility, and polymer distribution mode.

It is demonstrated that applying polymer in a secondary mode offers significant benefits due to high remaining oil saturation, especially for fields with high permeable formation and oil viscosity. Laboratory and field data from similar projects were used to benchmark the inputs for the dynamic models that were used to forecast the oil recovery due to polymer flooding.

Despite the encouraging oil production forecast due to the polymer flooding, several alternative development scenarios were investigated, including infill drilling and waterflooding. It was found that injecting polymer is the best option due to the highest ultimate oil recovery and lowest GHG emission intensity of produced oil. Polymer project economics is also advantageous, including the surface optimizations applied regarding polymer facility and distribution. The project is expected to accelerate the production peak, reduce decline, and allow better facility and urban planning design.

This paper illustrates the application of polymer injection in a secondary mode in a complex Gharif reservoir with heavy oil. This method can lead to a new polymer application strategy in future PDO fields.
Deciphering the Potential of Surfactant-Assisted CO2 Mobility Control: Insights into the Transient Foam State
Authors: Ding Lei , AlOtaibi Mohammad , AlYousef Zuhair , AlSofi AbdulKareem M.
Published: April 2024

Foam-assisted CO2 mobility control can enhance CO2 utilization and storage efficiency during enhanced oil recovery and carbon sequestration processes. CO2 is typically injected at larger gas fractions (fg) to reduce the surfactant costs, which, however, may result in significant retardation of foam generation/propagation due to high minimum pressure gradient (MPG) and surfactant adsorption. This study aims to minimize the transient foam state and optimize the foam process for maximizing the CO2 utilization capacity.

The design of a foam process mainly focuses on the foam behavior at steady states, e.g., foam apparent viscosity and transition foam quality. However, the foam steady state may take several pore volumes (PVs) of throughputs, which is difficult to achieve in the field tests. Therefore, the transient foam behavior (e.g., the onset of foam generation and foam apparent viscosity in the first several PVs) is more critical and needs greater attention. We evaluate a CO2 foaming system using switchable amine surfactants by performing core-flooding experiments and numerical simulations at 65°C and 150 bar operating conditions.

The evolution of CO2 foam apparent viscosity at various fg shows that the foam becomes stronger, yet the transient state becomes longer at elevated fg. The results indicate that the retardation of foam generation at high fg is resulted from high MPG and a low in-situ surfactant concentration. The in-situ surfactant concentration is influenced by the injected surfactant concentration, adsorption on the rock, dispersion, and surfactant partitioning behavior. The simulation results suggest that the retardation at transient states can be minimized by tuning the surfactant concentrations, fg, and injection sequence, to reach the strong foam and high CO2 saturation in a much shorter injection period. The experimental results demonstrate that foam is triggered more rapidly at low fg. Moreover, the retardation of foam propagation at transient states is further reduced by injecting a high surfactant concentration and a low fg in the initial stage and then progressively proceeding to higher fg and lower surfactant concentration. It is hypothesized that high surfactant concentration can rapidly compensate for the dilution of surfactant (by partitioning, dispersion, and adsorption) and enhance the foam generation and its propagation.

The retardation of foam at transient states will cause a series of operational and economic problems, thus, should be minimized as much as possible. An improved injection strategy is developed in this study to diminish the retardation of foam at the transient state from 16 PV to 1.9 PV, which can maximize the mobility control of CO2 and storage efficiency of CO2 in saline aquifers.
Multicomponent Gas Transport Modeling in Nanopo Rous Media with Adsorption
Authors: Babatunde Kawthar , Emami-Meybodi Hamid
Published: April 2024

Multicomponent gas transport in nanoporous adsorption media, such as organic-rich shales, is influenced by various mechanisms of mass transport and storage, posing challenges to understanding fluid transport in these porous media. We present a predictive diffusion-based model for the transport of multicomponent gas through nanoporous media using modified Maxwell-Stefan formulations for the free and sorbed phases. The developed model considers the transport of free and sorbed phases through nanopores and incorporates the extended Langmuir isotherm for multicomponent adsorption. The diffusive mass fluxes for both phases are coupled to obtain the governing equations with multicomponent effective diffusion coefficients and capacity factors that account for adsorption. The governing equations are functions of the free-phase composition and pressure and are solved numerically. The model is utilized to conduct a sensitivity analysis of the effective diffusion coefficients, capacity factors, and sorbed-phase porosity with respect to the pressure and fluid composition. Furthermore, co- and counter-diffusion processes are simulated to investigate CO2/CH4 flux from and CO2 injection into organic-rich shale and coal samples, representing moderate and high adsorption capacity systems. The pore-volume fraction of each phase is calculated to determine the overall contribution of the phases to total gas transport. The results show that the sorbed phase occupies nearly half of the pore volume in the chosen coal sample. The results also show that the diffusion coefficients for CH4 and CO2 in shale and coal are inversely proportional to the adsorption capacity. Thus, low or moderate adsorption systems have higher effective and apparent diffusion coefficients. During the co-diffusion process on the shale sample, the sorbed phase stops contributing to production after 12 months but continues to produce in the coal sample even after 12 years of production. For the counter-diffusion process in coal and shale samples, CO2 takes up the sorbed phase faster than it does the free phase, leading to a faster decrease in the sorbed phase concentration of CH4. For both co- and counter-diffusion processes, the sorbed phase concentrations are higher in the coal sample than in shale, while the free phase concentrations are higher in shale samples than in coal. The contribution of the sorbed phase to the total mass is dependent on both pore size and adsorption affinity for low-pressure systems while it depends only on adsorption affinity for high-pressure systems.
Optimizing Enhanced Oil Recovery: The Benefits of Preceding ASP and SP Floods with Polymer Flooding
Authors: Southwick J. G. , Driver J. W. , Dean R. M. , Aitkulov A. , Ravikiran R. , Nieuwerf J. , Rivas C. , Dupuis G. , Thomas A.
Published: April 2024

This study aims to illustrate the benefits of polymer injection before other chemical processes, e.g., ASP, SP, ACP, etc. Data in the literature showcases the benefits of polymer pre-injection, but the information is not organized into a coherent, unambiguous study to enable operators to confidently move forward with polymer projects where other chemical processes will be implemented in the future. Furthermore, a train of thought states it is deleterious to inject polymer in advance of a surfactant-based flood because viscous fluid ahead of surfactant could slow down chemical front propagation, and oil recovery.

The benefits of reduced surfactant mass with alkali and polymer pre-flooding have been shown in optimization work (Dean, et al., 2014). The highly successful Mangala ASP project (Pandey, et al., 2016) followed a well-established polymer flood. The Sabriyah Mauddud ASP pilot also used a polymer pre-flood to increase injectivity into low permeability zones. Laboratory studies (Dean, et al., 2014) show polymer pre-injection for the successful ASP pilot in Minas (Masduki, et al., 2020).

Aitkulov (2017) showed improved recovery, reduced surfactant retention, and better conformance when a heterogenous 2-D reservoir model in the laboratory was polymer flooded before ASP flooding rather than waterflooding.

Commercial simulators do not properly model surfactant phase behavior. Polymer is better modeled with the Jouenne model (Jouenne & Levache, 2020) in UTCHEM with salinity changes such as those seen in chemical floods. This study uses the mechanistic simulator UTCHEM to history match both of the heterogenous 2-D experiments in Aitkulov (2017). The first case shows water injection before ASP, whereas the second case shows polymer injection before ASP.

The history-matched parameters were then upscaled to a reservoir model. Due to existing ASP studies in Milne Point, it is also suggested to history match the most favorable ASP coreflood to obtain the proper inputs for the field scale model. The conformance learnings of Milne Point, e.g., the drop in water-cut shortly after polymer injection, indicate that the polymer injection is improving conformance and not allowing water to flow through pre-existing fingers, thus making the field a good example to simulate.
Development and Evaluation of Novel Emulsion and Foam Breakers for Chemical EOR Applications
Authors: Palayangoda Sujeewa S. , Pinnawala Gayani W. , Salman Mohamad , Griffith Christopher , Dwarakanath Varadarajan
Published: April 2024

Emulsion and foam are sometimes quite persistent in the oil field and can create numerous operational challenges in production facilities. Demulsifier and defoamers can play a role in demulsification and defoaming during field chemical treatments. There is demand for efficient and easily available emulsion and foam breakers for emulsion and foam issues especially during chemical stimulation/EOR flowback. The current inventory of commercially available oil field emulsion and foam breakers are typically not tailored to manage the complex chemistry of enhanced oil recovery. Identification of breakers tailored for chemical stimulation/EOR efforts is therefore essential for successful improved oil recovery. In this study, liquid and easily available partitioning agents were tested as emulsion and foam breakers with selective surfactants mixtures. Water soluble partitioning agents with relatively high partition coefficients were shown to be better foam and emulsion breakers compared to agents with low partition coefficients. The effectiveness of a partitioning agent in breaking foam and emulsions can vary depending on both temperature and salinity. Partitioning agents such as aryl-based chemicals tend to produce additional layer heavier than water during the emulsion breaking process due to oil interactions and should be avoided until further research is completed.
Advancement in Subsea Flexible Riser Installation Methodology
Authors: Ramesh S
Published: April 2024

The flexible pipe riser systems are used in various water depths and the advantages are well recognized in the oil and gas industry. The flexible riser systems are markedly advantageous with a floating platform such as FPSO, FPU, etc. The design of the Flexible product and the ancillaries can be custom made and hence, the flexible riser systems result in reduced hang-off load on the floating platform, have better fatigue outcome at the hang-off location and TDP. In general, flexible riser systems when used in suitable water depths will result in better performance over the lifetime, which has an outcome of cost optimization as far as the in-place performance is considered.

The broad optimization of the riser systems and in-place configuration many times leads to a set of challenges during the installation stage. Although the weather limitations during the installation process are relatively lower as compared to in-place configuration, some of the intermittent configurations formed during the installation process lead to the equipment subjected to much higher loads than the in-place configuration.

The installation loads on the product needs to be identified early in the design stage of the equipment. The early engagement and extensive engineering is performed in order to identify critical stages, provide optimizations, as well as mitigate any risks during the installation process.

This paper provides an insight into the engineering and development of practical installation methodology of complex Flexible risers system. The early development of the installation process and the identification of critical steps in order to mitigate the challenges involved which resulted in an optimized design of the equipment as well as avoiding any unexpected behaviors during the installation process. The findings from a recently installed riser system in the East coast of India is used as an example.
Novel Non-Damaging Fluid System Cured Losses in Large Fracture Networks and Established Well Integrity
Authors: El Zanaty O. , Kropochev Y. , Popov A. , Mukhamatyarov S. , Shahzad K. , Sarbast M.
Published: April 2024

The paper describes the use of ECD shielding novel fluid technology system along with engineering design method to effectively cement production strings under losses conditions. The studied wells were drilled in Kurdistan in the northern region of Iraq, an area where losses are a common drilling challenge due to naturally occurring fractures and high permeability in carbonate reservoirs.

The design allowed the operator to establish well integrity and achieve zonal isolation across production zones and minimize formation damage. The close collaboration between the operator and service company helped develop a fluid design and placement strategy that eliminated the need for remedial cementing jobs, thus providing a cost reduction and a reduced carbon footprint and helped obtaining reliable well testing information.
Enhancement of Process Efficiency by Implementation of an Improved Back-Allocation Logic for Gas Volume Computation: A Case Study
Authors: Sanyal S. , Soltybayev Y. , Al-Mutairi F. , Al-Qallaf A. , Al-Ajmi F. , Al-Ajmi A. , Barjas M. , Al Mutairi F.
Published: April 2024

Gas back-allocation evaluates process-efficiency in production domain by computing the contribution of individual wells to total production measured at surface facilities. In the case study, the previously deployed gas back-allocation method resulted in a substantial difference between measured and allocated gas volumes. To improve forecasting reliability, essential for all future expansion projects, the legacy approach needed to be revised and replaced by a more precise and robust methodology.

The legacy method of gas back-allocation relied on well-test gas measurements and oil back-allocation factor. With inherent inaccuracies in well-test gas measurement, and the separate surface-nodes utilized to measure oil and gas, the resulting back-allocated gas volumes were substantially lower than actual. An innovative approach was proposed to reconcile gas production at individual wells using daily estimated oil production, and a combination of GOR from PVT and well-test measurements, to compute the total summation of produced gas and compare that with gas measured at each sub-center. This would imply relocating the gas back-allocation node from Asset level to sub-center level.

The primary objective for method revision was to reduce inaccuracies introduced during gas-rate measurements at well-test level and further compounded by human error during validation of the test results. The revised logic introduced the concept of using guiderails of reservoir-specific GOR values, as obtained from PVT analyses and deploy an automated test validation process to filter-out all incorrect GOR values at the well-test level, which can be considered as the Input end for back allocation. Since gas volume computation at individual wells require both GOR and oil rates, accuracy was further enhanced by utilizing daily estimates of oil production per well, computed with the combination of latest well-test data, historical decline rates and well uptimes. At the output end, it was proposed to assign sub-centers, which are essentially the metering points for surface gas, as nodes for top level of the network to calculate gas back-allocation. With this method, each sub-center, attached to a specific field and reservoirs, would have its own gas back-allocation factor. This would also be a distinct departure from the previous method that assigned a single allocation factor for the entire asset.

The case study suggests a novel approach of increasing computation accuracy for cases with restricted data availability or questionable accuracy of raw data. Implementation of the new logic revised the allocated gas to within 10% of the total measured gas volumes at the Asset level. It has further provided the opportunity to re-visit the gas metering accuracy and meter re-calibration requirements for each sub-center and evaluate gaps in historical PVT data for individual fields and reservoirs.
Through Barrier Flow and Integrity Diagnosis of Complex Completion Enables Targeted Remediation to Reduce Water Cut and Restore Productivity
Authors: Al-Quoud K. , Elias M. , Al-Zoabi A. , Raffi M. , Sergeev E. , Petrova I. , El Dine S. , Vishnu R.
Published: April 2024

Well completions featuring an ICD, swell packers and sliding sleeve doors (SSD) are a popular option in highly heterogeneous reservoirs and homogeneous with barriers. However, this arrangement presents challenges for evaluating the integrity isolation in terms of the swell packer's isolation of layers. The subject well, an oil producer in Raudhatain field, Kuwait, was completed with an ICD with seven packers and five SSDs. The well showed a 100% water cut from the start of production. This paper describes a technique that combines high-precision temperature surveys and a spectral acoustic method to enable accurate flow profiling and integrity evaluation in such wells.

A diagnostic survey was planned for the subject well. This was designed to determine if there was flow from below the survey interval, establish whether the SSDs were active and check the integrity of the swell packers. This comprehensive study combined results from high-precision temperature surveys and spectral acoustic surveys. The analysis identified the contributing intervals of the formation behind the ICD blank zone. Each of the swell packers was assessed for possible leaks and the performance of each SSD was evaluated. The survey indicated that two of the SSDs were not contributing to production and that one of the swell packers was being bypassed. The temperature divergence between shut-in and flowing and temperature gradients suggested a significant inflow of fluid from a source, below the survey interval.

The survey provided an accurate evaluation of swell packer and SSD performance and enabled the operator to formulate an effective and efficient remediation strategy. This operator performed a straightforward workover program that involved setting a coilflate (plug) in the ICD shoe where damage was found. Confirmation from the diagnostic survey that the swell packers were holding above the planned depth for the plug suggested that this kind of workover would be effective. After confirming that the plug was holding (by pressure test), a surface-produced gas oil ratio (PGOR) test showed that the water cut in the well had been reduced to 74% and there was now a significant inflow of oil. The result of the diagnostic survey and subsequent workover operation enabled the operator to kick-start production from what had been a nonproductive well.

The combination of a high-precision temperature survey and a spectral acoustic method enabled accurate flow profiling and integrity evaluation in a well with ICD, swell packers and SSDs. These accurate assessments of reservoir flow and well condition would not have been possible with conventional production logging [PLT] techniques.
Derisking Low-Tension-Gas Flooding in a Carbonate Field in North Oman: Results and Insights from a Successful Foam-Assisted WAG Injection Pilot
Authors: Al-Abri Mohammed , Al Mahruqi Dawood , Al-Aamri Nawal , Das Anindya , Kahrobaei Siavash , van Batenburg Diederik , Jeroen Groenenboom , Abram Peter , Ramez Nasralla , Abuawad Ahmed , Farsi Samya , Jamaei Hana , Al Shabibi Hatem , Al Bulushi Abdullah
Published: April 2024

Lekhwair is a medium-large low-permeability carbonate reservoir in Northern Oman in a mature waterflood stage. To address the challenges of EOR in this reservoir, Low-Tension-Gas (LTG) flooding has been identified as a promising technology. The LTG concept is to use surfactants to reduce the interfacial tension between water and oil to mobilize residual oil in combination with foam for conformance control. In practice, for each goal different surfactant types are required. The objectives of this paper are to present the results and insights gained from the first successful foam pilot of LTG flooding in Oman. This pilot focused on the first objective of improving gas conformance by demonstrating the in-situ foam generation through Surfactant Alternating Gas (SAG) injection.

The injection plan consisted of 5 cycles of immiscible Water-Alternating-Gas (WAG) injection using N2 to establish a baseline, followed by 11 cycles of Surfactant Alternating Gas (SAG) injection for foam generation. A robust surveillance program was implemented for real-time monitoring of pressure responses, saturation profiles, and reservoir fluids dynamics, ensuring a detailed evaluation of the SAG flooding process.

The pilot successfully achieved its objectives. Foam generation through SAG injection was confirmed. Bottom hole pressure data demonstrated increasing trends during SAG stages, providing evidence of foam generation within the reservoir. Logging data validated flow diversion from high-permeability to low-permeability zones. The integration of field data for history matching the reservoir dynamic model allowed for better understanding of the SAG process and to evaluate the feasibility of several development concepts.

The single-well pilot demonstrated the successful generation of in-situ foam through SAG injection. This achievement has profound implications for maturing LTG technology in low-permeability carbonate reservoirs in Oman. The success of this pilot contributes novel insights into the application of Low-Tension-Gas (LTG) flooding in low-permeability carbonate reservoirs and opens exciting opportunities of chemical EOR in Northern Oman.
Novel Workflow to Properly Assess the Potential of a Naturally Fractured Gas Reservoir in a Tight Matrix Sandstone
Authors: Ruffino R. , Avanzini A. , Bianco A. , Marino R. , Bigoni F. , Albertini C. , Tarantini V.
Published: April 2024

The North-African asset under evaluation is characterized by a tight matrix sandstone with poor petrophysical properties, although with natural fractures that sometimes improve the well performance. In this context, the simple description of the matrix system can result inadequate, therefore a dual media modelling (matrix & fractures) was performed, capable of capturing petrophysical heterogeneity and reproducing observed well deliverability.

Given the uncertainties related to fractured systems, a Petrel RE uncertainty workflow was properly designed to evaluate the impact of different parameters on DST matching, future production profiles and well behavior through a Monte Carlo risk analysis. The workflow incorporates different combination of natural fracture scenarios (extracted from seismic curvature), matrix block size and microfractures diffusion (observed at core/well scale) in the matrix system, together with petrophysical parameters. Since some historical well performance was improved by hydraulic fracturing, this action was also considered in the uncertainty workflow.

The outcomes show, on one hand, that the well start-up rates are dependent on the hydraulic fracture interaction with the natural fractures system in the near wellbore area, on the other hand the well performances (gas cumulative and plateau length) are influenced by the connectivity of the DFN and the diffusion of micro fractures in the matrix system. Among all the investigated parameters, the most impacting on well deliverability are: different seismic DFN scenarios, fracture permeability, matrix-fracture interaction and the microfractures diffusion. The automated parametrization of these variables allowed to generate multiple scenarios for infill wells placement and recovery maximization. This workflow works as an effective and powerful tool to properly evaluate the asset.

This novel approach has been successfully tested in a naturally fractured gas reservoir characterized by a generally tight matrix sandstone. All the recognized uncertainties were combined in a sophisticated, yet user-friendly workflow allowing a robust asset evaluation.
Methodology to Estimate the Optimum Reservoir Operating Pressure and Envelope
Authors: Al Balushi F. I. , Al Amri S. S.
Published: April 2024

Petroleum Development Oman (PDO) has recently embarked on a journey towards maximizing reservoir throughput and improving waterflood efficiency across its large portfolio of fields undergoing secondary recovery via waterflooding. It was observed that, in most of the waterflood developments reviewed, there was a lack of understanding of the reservoir operating limits, and the concept of an optimum operating target by subsurface engineers. A methodology is developed to estimate the optimum reservoir operating pressure target to maximize throughput and visualize the reservoir operating envelope of waterflooded reservoirs by identifying the reservoir offtake and intake limits which are calibrated with actual field data. The approach is based on identifying the reservoir Intake and Offtake limits and plotting the Inflow & Outflow Performance Relationships derived from average well performance data within a pattern to visualize the reservoir operating envelope. It utilizes the well productivity index equation to build the relationship between the reservoir limits to derive the Optimum Reservoir Pressure target at which maximum offtake and intake at an instantaneous voidage replacement ratio (iVRR) of ∼1 can be achieved within the defined limits (i.e., Maximum Throughput). The workflow and method are described in detail to allow the readers to replicate approach.

The methodology has been assessed on several waterflood development projects across PDO covering clastic and carbonate reservoirs with varying properties, well types (vertical and horizontal) and pattern types. The workflow was found to provide engineers with a deeper understanding of the reservoir operating limits for a given pattern that allows them to quickly assess pattern performance against benchmarks and make well informed decisions. It allows for setting a target reservoir pressure with a technical basis that is calibrated with actual field performance and can be continuously reviewed as fields mature. It was also observed that the method provides for an assessment of the efficiency of pattern configurations where producer to injector ratio is greater than 1, and a parameter sensitivity analysis to support in well optimization decisions. Understanding the reservoir operating envelope is critical in waterflood developments to optimize a pattern's well offtake and intake, maximize reservoir throughput, and optimize pattern configuration.

The novelty of this method is to standardize an approach across the company to identify the Reservoir operating limits by outlining the workflow to define and visualize the operating envelope for a given pattern that is calibrated with actual field data and derive the optimum reservoir operating conditions (rates and pressures).
Evaluating Waterflood Efficiency with Multiwell Retrospective Pressure Analysis
Authors: Zholaman A. , Yergaliyev K. , Zharylgassov Y. , Krichevsky V. , Surmasheva L. , Farakhova R.
Published: April 2024

The efficiency of waterflood becomes crucially important when initial reservoir pressure is depleted and the aquifer is proven to be weak. In order to maintain pressure, one must carefully calculate injection / production wells rate, injection targets, define the optimal locations for new injection wells or justify switching producers to water injection. All of these tasks require the cross-well pressure impact data. Paper describes solution of these tasks on a field in Aktobe region, Kazakhstan.
Laboratory Synthesis and Evaluation of Phosphorous-Tagged Polymeric Scale Inhibitors
Authors: Chen Shaohua , Aljeaban Norah A. , Chen Tao , Huang Tianping
Published: April 2024

Polymeric scale inhibitors (SIs) possess excellent dispersive and scale inhibition properties. In this study, a series of phosphorous-tagged polymeric SIs (PPSIs) were synthesized to inhibit calcium scale formation in synthetic brines. The design of chemical structure followed previous evaluation results from commercial polymeric SIs to make the synthesized products maintain a high efficiency of scale inhibition. The phosphorus tag of PPSIs will facilitate the detection of SIs for operators to plan a reasonable squeeze treatment. Among three commercial SIs, AA/AMPS was the best one with a scale inhibitory efficiency of 100% at above 75 ppm. While HPMA exhibited little effects on inhibiting scale formation. Regarding the synthesis work, two polymer series including six specific PPSI samples were synthesized using 1 mol% of diethyl allylphosphonate and various AMPS or SSA and AA. 31P NMR spectra exhibited only one peak which corresponds to DEAP as the phosphorous tag. 1H NMR spectra indicated correct chemical structures of the PPSIs. The synthesized PPSI products showed good thermal stability, high efficiency in scale inhibition, and most importantly, the phosphorous detection by ICP. SEM images showed that the cubic and needle-like morphology of CaCO3 and CaSO4 scales were both significantly deformed upon addition of the PPSI to avoid the scale formation at a macroscopic level. After injection of one synthesized PPSI sample at a high concentration (10 wt%) followed by a shut-in period of 24 hours, permeability of the carbonate core plug was slightly changed, suggesting a low formation damage to the carbonate reservoir. After the post-flush of reservoir brine, the concentration of PPSI was still higher than the minimum inhibitor concentration (MIC), indicating an effective scale control during the squeeze lifetime.
A Novel Time Series Approach to ESP Gas Lock Predictive Classification Based on Dynamic Time Warping & K-Nearest Neighbor
Authors: Ghanduri Fatima
Published: April 2024

Electrical Submersible Pump (ESP) systems are a widely used Artificial lift method in the Oil and Gas industry- however, they do present failures with consistent use, as does any other tool. It is important to reliably predict the onset of damaging operating conditions and take proactive action to prevent early failure of ESPs.

Data processed from ESPs are considered time series due to their time-sensitive occurrences. Deep learning methodology needs to be adapted to the time series conditions of this data. Current deep learning methods deployed in the industry have demonstrated superior performance under the general requirement of the availability of a large set of training instances. However, many lack the efficient adaptability of the time component in the prediction of tool failure. Existing solutions do not further consider detecting signal similarity and reliable time alignment between pattern-matching measures. With this, we propose the use of K-Nearest Neighbor (KNN) with Dynamic Time Warping (DTW) as a distance-based classification method to classify the deficiency of a tool accurately and efficiently while considering pattern matching in specified time intervals.

The amalgamation of DTW and KNN is considered an effective method for time series classification of ESP gas lock prediction. Although the time complexity of this approach is considered as lower efficient than that of methods such as Time Series Forest Classifiers and Support Vector Machines, our approach optimises the search space and speeds up the execution at a more effective rate, thus providing a novel way for ESP predictive maintenance.
Improvement Strategy Heating and Drainage in Reservoir Complex Structure with High Faulted and Dipping in Area-9 D Field Heavy Oil Steamflood
Authors: _ Fatichin , Anggreini Selvyn , Pradana Candra Arya , Nugraha Baruna Satria
Published: April 2024

D field is the world's most significant operational steam flood that is currently produced from 13 existing areas. Area-9 is the most structurally complex in the D field. The existence of many faults and reservoir dipping is the primary issue that creates a complex compartmentation in the reservoir with faulting orientation mostly NE-SW and dipping to the East direction. The complexity of structure in Area-9 impacted the connectivity problem of producers’ and injectors’, caused reservoir heating and drainage not optimum, and impacted a low current recovery factor (RF) of ~45% compared to other mature areas with RF of 80%. The previous strategy to improve drainage and production in Area-9 by performing chemical jobs in many immature wells could not have improved heating, drainage, and production more effectively. A new strategy implemented to improve drainage, heating, and production in Area-9 established using the Area-9 conceptual model aims to get a deeper understanding of injection and production performance that links to faulted reservoir and compartmentalization. The improvement jobs that were applied for the Area-9 conceptual model are reactivating some of the idle steam injector wells in both surface and subsurface facilities to improve the heating of immature wells and patterns, performing some stimulation steam cyclic injection in surrounding producer wells located at the down dip of the pattern to connect steam between producer to an injector that can improve heating and drainage of the reservoir, perform some of the chemical stimulation jobs for mature well to improve well and pattern drainage. Ensure the reservoir temperature is already hot (mature) to ensure the chemical material works appropriately. By performing a new strategy, using Area-9 conceptual model successfully proved to improve heating, drainage, and production and unlock significant remaining oil opportunities. Some achievements of implementing the new strategy are improving heating by 30 – 60 deg F/job, increasing oil production by 7-15 bopd/job, and improving declining production performance in 2021-2022 (+2%) compared to 2020 (-7%). This effort has become a lean sigma project with a total Actual Financial Benefit (AFB) of ~ $2.5 MM. The next plan for applying a new strategy to improve heating and drainage in Area 9 is to consistently execute proactive thermal stimulation jobs and reactivate some of the injector wells. Future develops pattern alignment in Area-9 by adding more producer, injector, and observation wells to be aligned to the Area-9 conceptual model.
Integrating ASP Flooding into Mature Polymer Flooding in Marmul Field in Southern Oman
Authors: Mahruqi Dawood , Karpan Volodimir , Rawahi Hamza , Abri Mohammed , Aamri Nawal , Farsi Samya , Battashi Mundhir , Amri Sulaiman
Published: April 2024

The Marmul field is a medium-large mature oil field situated in the Southern part of Oman. Due to the relatively high viscosity of Marmul crude (~90 cP at reservoir conditions), polymer and ASP flooding were selected as the technology to improve the oil recovery beyond that of waterflooding. The commercial-scale polymer flooding in Marmul has been ongoing since 2010 and recently further expansions plans were announced. ASP flooding was extensively studies through the laboratory tests and field trials. Two field trials (Pilot and Phase-1A) with different ASP formulations and targeting different target reservoir intervals indicated a potential of 20-30% incremental oil recovery due to ASP injection after the water flooding. In the ongoing ASP field trial (Phase-1B project), the ASP solution is being injected in the quaternary mode to test the post-polymer performance of ASP flooding under field conditions. Post the technical success of the ASP Phase-1B project, the task was to identify the optimal concept for the ASP flooding in the Marmul field.

A hybrid approach based on numerical modeling and data-driven capacitance-resistance modeling was proposed to calculate the incremental oil recovery due to ASP flooding for the well patterns. Moreover, this publication presents the approach to integrating the ASP flooding into the mature polymer flooding in the Marmul oil covering both subsurface and surface aspects.

Marmul well patterns are both water and polymer flooded; hence an attempt was made to evaluate the efficiency of ASP flooding for both post-polymer and post-water injection conditions. Data from core flooding experiments and field trials were used to forecast the efficiency of ASP flooding post-water and post-polymer flooding. Moreover, to take into account the properties variation across the field a set of field parameters such as reservoir heterogeneity and mineralogy, remaining oil saturation and its distribution, well performance, etc., was used to forecast the performance of ASP flooding in different well patterns. Resulting pattern-specific oil recovery was used in an economic evaluation to select the optimal concept for the commercial-scale ASP flooding project in Marmul.
An Integrated Governance Technology Based on Magnetic Steering System for Cementing Plug in Open-Hole Section of Underground Gas Storage: Theoretical Analysis and Field Test
Authors: Che Yang , Yuan Guang Jie , He Ai Guo , Qiao Lei , Liu Tian En , Fang Ming Xing
Published: April 2024

The paper describes a comprehensive control technology based on a magnetic steering system for plugging the cementing plug in open holes without clear beacons in underground gas storage (UGS).

Utilizing depleted oil and gas reservoirs for natural gas storage is an important approach towards achieving carbon neutrality. Plugging old wellbores that affect sealing performance is prioritized according to relevant standards.

The challenge with open holes with cement plugs is that there are no clear beacons in the wellbore, and the extent of compaction is unknown. Accurate positioning of the cement plug is crucial and the current technical methods, such as electromagnetic and acoustic waves, have limitations. Magnetic steering technology, which is mature and widely used in drilling complex structure wells, requires beacons like pipes and metal pipe strings. On the other hand, acoustic positioning technology is still experimental and suffers from large distance and azimuth errors due to the attenuation characteristics of acoustic waves in heterogeneous formations. These existing technologies are unable to directly position open holes with cement plugs.

The paper proposes a comprehensive control technology based on the magnetic steering system. It starts by measuring the positional relationship between the drilling wellbore and a magnetic reference wellbore using the magnetic steering system. The skew data is then used with the ISCWSA model to determine the location of the plugged wellbore and the magnetic reference wellbore. By calculating the relative positional relationship between the drilling wellbore and the plugged wellbore, the cement plug reentry can be achieved within the error ellipse range below the sidetracking point. After reentry, specific work such as crushing, element logging, caliper logging, and full hydrocarbon gas detection is performed to verify if the wellbore is still in the original position and if the caprock is properly squeezed and plugged.

The comprehensive treatment technology plan was tested on five wells in the Bohai Bay, successfully addressing the problem of positioning open holes with cementing plugs. The process system expands the field of magnetic guidance technology and demonstrates significant industrial application value. It provides a means of plugging complex old wells.
Incinerator Performance Improvement by Preheat Feed Streams Using its Produced Steam_ Reduce Operation Cost & CO2 Emission
Authors: Alzamzam W. S.
Published: April 2024

Sulfur Recovery unit is an essential part in Oil Refinery and gas treatment unit, it consist of MDEA enrichment unit, Claus Unit, Tail gas treatment unit and thermal incineration unit. Incineration process is used in order to make the process effluents releasable into the atmosphere. In which the hazardous and pollutant sulfur containing compounds are converted to sulfur dioxide. The case study of this work is about an existing thermal incinerator in Sulfur Recovery Unit, its streams are mainly consist of combustion air, MDEA waste gas, tail gas and fuel gas. Feed stream temperatures will be maximize more than current operating temperature in order to reduce fuel gas consumption and CO2 emission as well. The idea is utilized the produce high pressure steam from its Waste heat Boiler WHB to preheat feed stream including combustion air 40°C and tail gas 140°C and MDEA waste gas 40°C. in this study the target preheating temperature is 290°C for each stream. PROMAX Software is used as simulation tool, three scenarios have been chosen including maximize tail gas temperature, combustion air temperature and finally waste gas temperature. All input field date have been collected from operating system called distribution control system (DCS). Result show remarkable reduction of fuel gas consumption and CO2 emission for three scenarios (12.5%, 26 % and 36% respectively) comparing to existing situation for the case study. So installing high pressure steam pre-heaters on feed streams is strongly recommended for this case study in order to reduce operation cost and CO2 emission.