Abstract Asphaltens presence in the reservoir fluid has great implications on downhole as well as surface facilities. These problems are not only related to production impact, but also significant integrity as well as surface facilities operational challenges are seen to affect the upstream oil and gas production facilities. Handling the asphaltenes rich fluid brings inherent challenges with it starting from well bore to the production facilities. Adequate engineering solutions need to be integrated into the design of production facilities as well as wellhead equipment which would greatly enhance production efficiency while successfully facing asphaltens challenges. The nature of asphaltens as well as their growth rate are not very well understood due to their complex chemistry with different hydrocarbons. Therefore there will not be a 100% success while managing the asphaltens, however these proactive steps would upto great extent would reduce the downtime and other asphaltene related impacts. This paper presents an effective way to address asphaltenes challenges as faced by surface and subsurface facilities in oil and gas production operations. Best industry practices for mitigating asphaltenes related challenges, which not only sustained the production but also enhanced asset integrity performance, have been presented for experience sharing and enhancing the asphaltenes handling capability. The reservoirs with asphaltenes presence are quite difficult to handle and maintain due to complicated nature of asphaltens, which result into various problems with downhole as well as surface facilities. These problems result into scales blockage of well bore and flow lines thus causing blocked flow and in most of the cases complete seizure of wells fluid flow.

Abstract Reservoir X is a giant oil reservoir of 30×10 Km 2 developed since 1973 using peripheral water injection. A major review study was done in 2016 highlighted major reservoir challenges that need to be managed and mitigated. The main challenges are (a) reservoir pressure decline in the central area (b) advancement of water cut/water conning (c) increased number of inactive strings (d) improper distribution of production offtake (e) inefficiency of current injection scheme. Consequently, reservoir deliverable potential has continuously dropped with increasing inactive strings threatening the attainment of the field mandated production target. This requires a major shift in our reservoir management strategies and best practices to cope with these challenges. In this paper, a case study for reservoir management in a mature carbonate reservoir with its detailed methodology is presented. An intensive and integrated technical work was conducted to (a) regain the target technical rate of 20% (300Mbpd) (b) arrest the pressure decline (c) implementation of a more efficient long-term plan to increase reservoir pressure and to maximize ultimate recovery. A detailed approach was developed which consisted of short, mid and longterm actions. This approach involves (a) re-prioritization of infill drilling through weighted ranking (b) pressure recovery implementation strategy through sectorization, re-balancing of production offtake and improving water injection efficiency (c) sector based evaluation using simulation/streamlines/data analysis for the voidage replacement (e) water injection optimization with the help of new peripheral water injectors, increased water injection availability (New clusters and network debottlenecking) and new Water Injection scheme (Mid Flank water injectors) (f) tracking the implementation of the Pressure Recovery Plan with a dedicated and tailored monitoring dashboard. Through this integrated approach a portfolio of wells is selected and ranked that help in achieving the objectives of the reservoir development efficiently and the 20% Technical Rate achievement. The sector wise analysis and tracking approach enabled in arresting the pressure decline in the crestal area and ensured that the focus remained on the recovering pressure in the worst affected areas of the reservoir while meeting the production requirements. Another important outcome of this work was to drive a slew of initiatives related to the improvement of water injection efficiency that is a necessary requirement to recover the pressure in the crestal area. This reservoir management methodology and framework put in place provides a platform to continuously integrate the inputs (production/injection; VRR; pressure) and develop understanding from the different disciplines of the reservoir development to monitor and manage the reservoir in and efficient and timely manner.

Abstract Many horizontal wells in GCC (Gulf Cooperation Council) are producing from fractured carbonate reservoirs under aquifer pressure support. After water breakthrough, these wells suffer from high water cut rise due to water channeling through the fractures, inducing a strong and quick loss of well productivity. The wells being completed horizontal open hole, zonal isolation is very difficult to isolate the water producing zone. Moreover, mechanical water shut off like using liners or open hole packers is normally costly and challenging as well. Therefore, bullheading chemicals is often the only remaining option. The fractures being producing mixture of both oil and water, water shutoff in this type of well is very challenging. To solve this problem, an original method was used consisting of microgel and gel injections. The strategy is to create a flow barrier deep in the fracture while preserving oil production from the matrix. The optimized procedure enables control of chemical placement by bullhead injection. Laboratory tests were conducted to optimize Microgel and gel chemistry (injectivity, gelation time and gel consistency/stability, return oil permeability). The treated candidate was 530m long horizontal well and produced at around 600 bpd with water cut of 92%. Temperature and salinity were 62°C and around 100,000ppm respectively. Well behavior indicated existence of fractures along the wellbore. The treatment consisted of 230m3 of successive Microgel/Gel injection at an average rate of 2.5 BPM. The treatment proceeded bullhead through annulus. WHP remained low throughout injection (150 psi). After curing time of 10 days for gel set, production was released with ramp up rate. The well, which was facing strong production decline, stopped declining, with a water cut drop of around 10%. Incremental daily oil rate was around 50 bopd with cumulative oil for the first 4 months of around 4500 bbls of oil. This technology may have many applications in fractured carbonate fields and may lead to better oil potential from such high water cut highly fractured reservoir wells, with strong aquifer.

Abstract Polymer flooding is a mature EOR technique successfully applied commercially in sandstone reservoirs and at the pilot stage in carbonate reservoirs. However, all previous pilots in carbonates reservoirs were implemented in relatively low temperature and low salinity conditions. No field application of polymer in carbonate was implemented in the last 25 years. In recent EOR screening studies for carbonate reservoirs in Abu Dhabi, polymer based EOR techniques were identified to target by-passed oil in heterogeneous/layered reservoirs The main challenges for polymer based EOR processes in ADNOC reservoirs is to find a stable polymer under the extreme conditions of high temperature/high salinity/high content of divalent cations which can be injected in carbonate reservoirs. An extensive laboratory program initiated 10 years ago led to the development of a polymer rich in Sodium Acrylamido tertiobutyl Sulfonate (ATBS). Thermal stability, bulk and in-situ rheology, adsorption and injectivity performed and the polymer was found suitable for the harsh conditions of ADNOC reservoirs. A de-risking strategy was designed in which a polymer injectivity test (PIT) followed by a multi well pilot are performed before the full field implementation of polymer based EOR for a number of ADNOC reservoirs. This paper describes in details the main steps of the successful PIT recently carried out including: the selection of the candidate well and the injection skid, the test design, its execution, the polymer solution quality management and the operational challenges faced during the pilot. The polymer Injectivity Test was conducted for 4 months and concluded by February 2020. A total of 150,000 barrels of viscous solution was successfully injected into the reservoir. This paper also details the real time surveillance and injection monitoring plans implemented during the test period for real time assessment of the skid delivery and the well response. This Injectivity test achieved the designed Key Performance Indicators related to polymer solution quality, viscosity, concentration, injection rate and skid running time. The dedicated surveillance and injection monitoring plan designed and implemented during this pilot, enables to confirm the good performance of the polymer during PIT period. Furthermore, PIT results showed good performance of Polymer in terms of viscosity, Injectivity at target rate and concentration. This paper also addresses the impact of water quality on polymer viscosity and skid operation. This paper presents field results for a new polymer developed for carbonate reservoirs at HT/HS. This successful Polymer Injectivity test qualified the new polymer for field application at harsh carbonate reservoir conditions. Results from this world first Injectivity test opens a new area of possibilities to improve recovery in giant heterogeneous carbonate reservoirs in ADNOC and in the Middle East.

Abstract The Greater Burgan field in Kuwait is the largest sandstone oilfield in the world. Kuwait Oil Company (KOC) recognizes that enhanced oil recovery (EOR) is of strategic importance to maximize recovery and extend field life. We studied several EOR options using reservoir simulation to evaluate the benefits of using low salinity waterflood (LSW), low salinity polymer (LSP) injection and high salinity polymer (HSP) injection applications in Wara and Burgan upper (3SU) reservoirs. Full-field reservoir-simulation with adequate resolution for EOR assessment of giant fields (e.g., Greater Burgan) is computationally expensive, if even possible. To overcome this, we ran high-resolution sector-models, representing different areas, with inputs from laboratory and single-well-chemical-tracer-tests and generated type-curve profiles (e.g. oil recovery vs. cumulative pore-volume injection). A scaling-up tool was developed that considers infrastructure-facility constraints (e.g., high- and low-salinity capacities and injection priority of field areas), combines type-curve profiles, and outputs field-level profiles. At sector-level, we optimized all EOR slug sizes. For cases with polymer, polymer concentration was optimized on basis of polymer amount required per incremental oil barrel. The following five development scenarios were studied: 1) HSP everywhere across Wara and Burgan (3SU) reservoirs 2) LSW everywhere across the reservoirs 3) LSP everywhere across the reservoirs 4) secondary LSW for certain areas of the reservoirs and HSP for remaining areas 5) secondary LSP for certain areas of the reservoirs and HSP for remaining areas. The scenario #3 shows the highest incremental oil as it adds the benefits of both LSW and polymer injection. However, using low salinity-polymer in conjunction with high salinity-polymer (i.e., scenario #5) gives the highest incremental oil peak rate. In general, polymer flooding reduces the amount of water production. Use of low salinity without polymer resulted in higher water production. Significantly less volumes of polymer are associated with low-salinity water injection as compared with high-salinity water injection. Optimal polymer concentration was found to be well above that which gave unit mobility ratio. Although, the EOR incremental benefits and their corresponding screening-level economics look reasonable for the EOR schemes investigated, the schemes vary significantly in feasibility, capital costs and operating costs. A long-term injectivity pilot of high-salinity polymer is planned. Our approach combines the understanding of recovery efficiency that comes from detailed type pattern modelling with understanding of realistic facility constraints to rapidly generate realistic field-wide projections. We evaluated several facilities options corresponding to the five EOR development scenarios and generated cost profiles that were used in economic modelling.

Abstract A critical issue in waterflooding operations is determined by reservoir heterogeneity, which generates preferential flow through high permeable paths limiting contact with oil bearing zones. The use of Thermoresponsive Polymers, a novel type of chemicals, has been evaluated as a method to improve the oil displacement by better addressing water flow through un-swept regions. The placement of chemicals able to impair the high permeable layers, blocking water and diverting flow to richest oil zones could improve the final oil recovery. We describe a method based on novel, water soluble polymeric materials characterized by thermoresponsive properties, inducing reversible viscosity variation. This type of temperature stimulated co-polymers are molecules subjected to a reversible transition in correspondence to a certain "lower critical solution temperature" (LCST). Below such critical temperature, the molecules are completely soluble in water (low viscosity), while in the range over the LCST, a phase transition occurs, creating a gel-like structure with a consistent increase of the solution viscosity. This phase transition could be exploited to decrease consistently the permeability of the area occupied by the fluids. These products have the potential, by proper tailoring of the chemical structure, to design the range of working temperature to match the reservoir peculiar conditions. After a first screening of different polymer properties by bulk tests, the final performance evaluation was done by core-flooding experiments. Clashach sandstone was selected as reservoir rock analog. The injectivity performance of the polymer solution (2% w/w), was measured by differential pressure monitoring. The permeability reduction, due to transition over the critical temperature (typically, 70°C in our experiments), was evaluated by permeability to brine measurements before and after the polymer treatment. The results obtained in terms of injectivity and permeability reduction are positive and promising for a field application. The polymers studied represent a novel class of products, sensitive to temperature, suitable for conformance control application. It allows a precise tailoring of their features, i.e. the transition temperature from low to high viscosity, adjusted to the temperature and permeability of the reservoir. These parameters need to be carefully estimated, before running the treatment, through a tracer campaign and reservoir simulation.

Abstract Chemical additives have often been added to injection water for enhanced oil recovery (EOR) from geologic formations in the oil industry. The oil clusters in porous mediums commonly remain in the microsized capillary elements such as pores and throats due to high capillary pressures or negative capillary pressures, which is a function of pore topology, interfacial tensions, and wettability. Recent studies show that tailoring the ion composition in the injection brine can be an effective way to alter the wettability of carbonate reservoirs, reverse the capillary pressures to positive values, and improve oil displacement efficiency. There are limited studies on the impact of dynamic wettability alteration on multiphase fluid flow in heterogeneous carbonate rocks. The dynamics of pore-by-pore displacement by smart waterflooding is still unclear. The objective of this research is to examine the process of wettability alteration in a natural carbonate rock by smart waterflooding and understand its impact on the microscale oil displacement. A carbonate rock sample was flooded with various amount of smart water within the first hour and after twelve hours, and the flooding cycles were visualized using synchrotron-based microtomography. The pore-scale observations demonstrate that the oil phase initially remains in the corner of the oil-wet pores after contacting with the smart water solution. After twelve hours, the oil droplets were remobilized to the center of the pores due to wettability alteration and favorable interfacial energies. This transition in the fluid occupancy enables the oil phase to form high-connectivity flow channels and subsequently resulting in oil mobilization and extraction from the porous medium.

Abstract Gel-based conformance control is a potential method to ensure optimal contact with remaining oil in heterogeneous reservoirs. Conventional gel screening focuses on evaluating bulk gel properties, such as the gelation time and the gel strength. Evaluation of gel in-situ properties is limited to residual resistance after gelation (static property). A clear understanding of the gel dynamic properties in-situ is necessary for accurate performance evaluation and numerical upscaling of gel-based deep conformance control applications. In this study, we present a representative technique to evaluate polymer gel dynamic properties. Continuous gelant flow experiments are performed in an 80-ft long slim tube at reservoir conditions. The porosity of the slim tube is 37.0%, and brine permeability is 8.5 Darcies. Multi-point pressures along the tube are monitored to evaluate the variation in the gelant's ability to flow. The time-dependent permeability reduction and in-situ gelation time are determined based on the pressure responses. With which, we conducted a systematic study of in-situ gelation of an organically cross-linked polymer gel system at 95°C. A low molecular weight copolymer of acrylamide and acrylamide tert-butyl sulfonate was used in this study, which was crosslinked by polyethylenimine (PEI). Bottle tests conducted on gels with different polymer and crosslinker concentrations showed that the gelation time of the studied gel system can reach up to 10 days at 95°C. This indicates the potential of the studied organically cross-linked gel for deep conformance improvement applications. In the slim tube test, the polymer solution is injected before and after the gelant slug, which helps to diminish viscous fingering and maintain the gel-slug integrity. The in-situ gelation time, determined as the time when a clear shift (significant increase) in pressure drop buildup rate is observed, was consistent with that determined by the bottle tests. The slim tube technique presented in this study can simulate the propagation of gelants through porous media across long distances at actual reservoir conditions, providing essential data for the upscaling and design of gel-based deep diversion treatments.

Abstract Carbonate acidization is the process of creating wormholes in carbonate rocks by injecting acid to increase reservoir permeability and consequent oil production. Nevertheless, some reservoir oils might contain certain amounts of asphaltenes that affect the wormholing process. During acidization in the presence of these asphaltenes, the injected acid might not effectively react with rock. This study illustrates the processes of interactions between acid, rock, and asphaltene. It is found that a cumbersome and intricate compound known as acid-asphaltene sludge is formed when the acid reacts with the deposited asphaltene. The formation of this sludge would reduce oil productivity and acid injectivity. In this study, a numerical model is developed to predict the amount of asphaltene deposition, acid-asphaltene reaction, and formation of acid-asphaltene sludge. A 1D numerical model was developed to predict the deposition of asphaltene and acid-asphaltene reaction in radial geometry. Then, the developed model was utilized to predict sludge formation and its related effect on reservoir permeability. Furthermore, the developed asphaltene deposition model was validated against two different sets of experimental data where various factors affecting sludge formation were determined. The detailed analysis showed that although sludge formation is few percent, its concentration increases with time and acid injection. The results also indicate that acid-asphaltene sludge causes an irreversible and permanent formation damage from 40 percent blockage to total pore blockage, depending upon the location of sludge deposition in pore body or pore throat, respectively. Hence, reduction in hydrocarbon productivity is expected at a much lower rate as opposed to that before the acidization job. In addition, the results showed that the amount of acid-asphaltene sludge formation depends on asphaltene percentage, acid concentration, acid flow rate, and flow period. To the best of our knowledge, there is no published work focusing on modeling acid-asphaltene sludge formation and its subsequent wormhole development. This paper provides more insight into the effects of asphaltene deposition and acid-asphaltene sludge formation on wormhole creation and propagation.

Abstract ADNOC Onshore is operating Habshan gas production field on behalf of Abu Dhabi National Oil Company (ADNOC). The gas reservoir production zones were developed under different project phases. The field has 250 gas (production and injection) wells, which are placed and located in approximately 1200 square kilometers. All gas wells are designed to have SCADA system to monitor, operate and control the wellhead control systems. Current practice within ADNOC Onshore is to carry out monitoring for Cathodic Protection (CP) of well casing and Chemical Injection (CI) surveys on quarterly basis, this is carried out by mobilizing entire crews physically (visiting every single location) and reporting findings/conditions in order to carry out preventive maintenance and necessary repairs. The aim of the project is to establish a remote monitoring system utilizing the existing Supervisory Control and Data Acquisition (SCADA) setup in order to monitor the applied corrosion controls, CP and CI injection systems. Based on the implemented modification, essential information was collected, intensive review and analysis were performed and revealed that the system is functioning perfectly as per the operation's requirement for both (CP & CI). This approach forms a vital aspect of the integrity management of the asset by monitoring the effectiveness of the applied corrosion controls, in addition, the implementation will help Operations to optimize resources, efficiently monitor, maintain, and ensure safety of the facilities and its integrity. Moreover, the implemented method will drastically reduce the associated travelling risk, limiting exposure to the harsh environment (Desert) and potential cost saving.

Abstract Large, complex and faulted structures often pose substantial challenges in maximizing hydrocarbon recovery. This is largely due to limited understanding of field wide connectivity of reservoir sands, across fault communication, and uncertainty in reservoir fluid contacts due to a fewer well penetrations in early life of the field. In addition, secondary recovery through water injection support brings further complexities in such fields, particularly in stacked reservoirs with multiple sands completed across individual production zones. The work presented in this paper has utilized ‘pattern reviews’ technique in a brown field containing over 500 well penetrations in South East Asia. Pattern reviews have made use of reservoir pressure data, fault maps, sand/shale correlations, salinity variations between formation and Sea water, and injection and production data by carving out specific sections of the field containing injector-producer pairs. The integrated data and analyses have helped establishing connections, or otherwise, between injector-producer pairs across various parts of the field. Time lapse Production Logging (PLT) campaigns were executed to provide additional supporting evidence on flushing of certain reservoir sands in producer wells and preferential injection zones in injector wells. Systematic selection of patterns containing injector-producer pairs across the field has provided a substantial support in our static and dynamic modelling work to establish reservoir/fault connectivity within fault blocks and across the field. This has subsequently helped in history matching production data as well as identifying infill opportunities for bypassed oil. The present work has also helped in optimizing water flood and choosing certain injectors/zones to open/close for pressure support. An understanding on the connectivity between injector-producer pairs has also helped in identifying areas with low recovery and poor sweep. This has paved the way in initiating a pilot project for Polymer injection in this field to help understand incremental recovery in addition to water flood. A successful outcome would initiate field wide polymer injection with a potential of 10's of mmboe incremental recovery from the field. For the first time in field history, pattern reviews have been extensively used as a tool to understand reservoir connectivity and dynamic fluid movements across the field. An additional attempt has been made to use ant track maps to help identify potential baffles and sub-seismic faults. An integrated effort between the various data and disciplines have provided fresh insights into the reservoirs and which would have otherwise been difficult in heterolythic nature stacked reservoirs.

Abstract Single-well chemical tracer tests (SWCTT) have received burgeoning interest as in-situ methods to measure the remaining oil saturation (S_or). The test not only involves field operations and lab measurements, but also relies on curve fitting of the data acquired from these procedures. Despite various types of errors and uncertainties arising in SWCTT, their effects on data analysis, and in turn the accuracy of S_or measurements, remain unclear. Here, we present a robust SWCTT simulator and use it to perform sensitivity analysis of different parameters over a wide range of reservoir and tracer properties. We find that accurate determination of tracers’ partition coefficients is crucial for estimating S_or, whereas errors in concentration measurements or pore volume characterization have less dramatic effects. More importantly, we demonstrate that matching the SWCTT data is only a necessary condition for the accurate estimation of S_or. In fact, a good data fitting without correct values of parameters such as partition coefficient could yield substantially deviated values of S_or. This sensitivity analysis and the "what-if" capability of our simulator provide in-depth understanding for the design and optimization of SWCTT.

Abstract Microsphere injection aiming at in-depth fluid diversion is based on the microsphere retention induced by the particle-rock/brine interaction in hydrodynamic environment. The retention generates steric blocking to the high permeability zones but retards the microsphere migration to the deep reservoir. This work studied the flow properties of microsphere samples in heterogeneous carbonate core plugs for an optimum blocking and migration capabilities. The oil production potentials of blocking-dominant and migrate-dominant microsphere samples were compared. Coreflooding tests were performed to evaluate the microsphere flow properties and oil production potential at 95°C and 3100 psi pore pressure. The carbonate core plugs with middle to high permeability were used. The flow property evaluation started with quantitative microsphere injection of eight pore volumes, followed by postwater injection. The injection pressures were recorded and produced microsphere concentrations were monitored. Oil displacement tests were conducted using selected microsphere candidates by 1 pore volume microsphere injection after waterflooding. Effects of microsphere sizes were investigated. The flow properties of eight microsphere samples with different particle sizes and aggregation properties were evaluated. Particle size was a dominant factor for the microsphere flow in the core plugs. Larger particles tended to retain in the pores rather than migrate forward, resulting in higher flow resistance with less breakthrough. Suspension in polymer solution improved the ability to penetrate deep into the formation. Microsphere with better coalescence stability in the brine showed better migration performance. Three microsphere samples with particle size at nano-, sub-micron and micron scale were selected to evaluate the oil production potential. One pore volume microsphere injection by the nano- and sub-micron microspheres after waterflooding increased oil production by 11% and 16%, respectively, which were much higher than the oil production by micron microsphere injection. A balance between effective blocking and deep migration was required to achieve optimal performance. The optimization process is developed for the microsphere injection in the field application.

Abstract The use of carbon dioxide (CO 2 ) for simultaneous methane recovery and CO 2 storage is gaining recognition globally within the oil and gas industries. On the other hand, most of the residual natural gas recovered during the EGR process is highly contaminated with the injected CO 2 due to their nascent miscibility nature, resulting in premature breakthrough. In this study, N 2 gas was used as a buster to mitigate such early mixing between the CH 4 and CO 2 . The experiment was administered at reservoir conditions of 40oC temperature, 1500 psig of pressure, the optimum injection rate of 0.4ml/min, and at varying N 2 cushion volumes (8-36 cm 3 ) using Bandera gray as the porous medium. Further experimental tests were administered to study the effect of this technique on connate water salinity with 5-20% water salinity been considered. The increase in buster gas volume was in direct proportion to delayed CO 2 breakthrough, with the maximum at 36cm 3 buster volume. This breakthrough occurred at 177 minutes which is 110min additional delayed than the conventional CO 2 flooding with a breakthrough time of 67 minutes. This was due to the high shielding barrier inhibited by nitrogen, making it difficult for the CO 2 to dispersed itself and mixed with the nascent natural gas resulting in delayed breakthrough as it plumes transverses into the CH 4 during the displacement process. Furthermore, a poor performance was observed with the inclusion of the connate water salinity, especially at 20% wt. This was because the free pore spaces were already occupied by connate water molecules prior to the cushion gas injection which hinders its economic potential application.

Matrix acidizing is one of the most common well stimulation methods in Malaysian brown fields. Formation damage caused by fines migration has been reported to be among the main reason for productivity decline. The need to conduct acid stimulation arises when the initial rates of the wells are below expectation or when the productivity of the reservoir drops significantly. Various mud acid formulations have been used to treat the wells from the past until recent years. However, some well treatments resulted in low success rate especially for reservoirs with vast variation and complex formation mineralogy. This highlights the need for modified acid recipe from the conventional mud acid system. Mud acid systems are often highly corrosive, resulted in unwanted secondary precipitation and require multiple additives during the treatment. This paper highlights the evaluation and comparison of the novel Modified HF acid against conventional mud acid system through core flooding tests. Multiple cores with various mineralogy were tested. The laboratory test showed that the Modified HF acid system able to generate better permeability improvement compared to mud acid systems. The modified acid recipe gradually sequestrates the major iron minerals throughout the injection to avoid unwanted secondary or tertiary precipitation that could damage the formation. Subsequently, the chemical was successfully piloted in two fields and replicated in other fields across Malaysia. The field applications proved that the novel Modified HF acid system generated outstanding results in production gain and improved the total economics of the project. The novel acid recipe can be an alternative solution when simpler acid systems are favored with lower treatment cost. This chemical is also beneficial for wells that located in small platforms or jackets where minimal amount footprint is available during job execution.

Substantial buildup of CaSO 4 and CaCO 3 scales downhole contributed to a loss of 10,000 BOPD and the shut-in of 12 of the 70 wells in a Middle East field. The mineral encrustation occurred on electrical submersible pumps (ESPs), motors, and throughout the entire downstream production systems. The root cause was identified to result from water injection of sulfate-containing seawater into calcium-rich formation waters of Burgan and Mauddud reservoirs. This paper presents a case history from scale prediction and laboratory evaluations to the squeeze intervention to demonstrate how an effective scale treatment strategy was set up and implemented. To mitigate the risk of scale deposition during production, a scale inhibitor squeeze treatment was designed and implemented in the field. The design process started with a comprehensive field survey conducted by a field-experienced technologist. Scaling risks were assessed using water chemistries not only from Upper and Lower Burgan and Mauddud reservoirs, but also under all mixing scenarios with seawater. The systematic performance, fluid compatibility, and stability testing were conducted to formulate a cost-effective, custom scale inhibitor that considered the water chemistry and conditions of the specific horizontal well. A collaborative effort between the chemical supplier and coiled-tubing team engineered an effective application procedure to minimize the loss of squeeze fluid due to refilling in the annulus and to deliver the scale inhibitor to targeted zones. This application technique maximized the effectiveness and lifetime of the squeeze treatment. The approach to squeeze treatment design combines extensive field experience and application engineering with custom, cost-effective chemistry to meet well-defined key performance indicators (KPIs). In this case, the product candidate demonstrated a superior minimum effective concentration (MEC) of 5 ppm, as determined by dynamic loop tests and static bottle tests, as well as a full range of brine compatibility at any given mixing condition in the reservoirs. Once the intervention was executed, continuous monitoring of the squeeze application demonstrated that the inhibitor residual concentration in the produced brine remained above MEC for ten months, effectively inhibiting scale during that period. A 55% increase in the treatment lifetime was achieved relative to the target of 180 days while recovering the oil production rate of the well, resulting in an increase of 1,000 BOPD. A revisit to the field confirmed that the scale treatment was effective and found no sign of scale deposition in the previous well locations. Modelling simulation was performed before the intervention and matched the field operation results. Future treatment design was also optimized. The squeeze treatment was carried out for the first time in the field with significant cost savings for the operator in comparison to the previous frequent chemical interventions for the wells involved.

Aqueous or hydrocarbon phase trapping is among few formation damage mechanisms which is capable of significant reduction in effective permeability even near to 100%. Phase trapping can occur by physical fluid displacement (during drilling, completion, stimulation or workover operations), crossflow from wet zones, co-current and counter-current imbibition or condensate banking around the wellbore. The remediation techniques including bypassing damage (e.g. hydraulic fracturing) or removal techniques (e.g. solvent or surfactant injection) are highly expensive or only effective temporarily. In this study, a new chemical treatment is proposed for efficient remediation of water or hydrocarbon phase trapping damage in low permeability porous media. Phase trapping or capillary trapping occurs inside pore structure when viscous forces are not strong enough to overcome the capillary forces. Increasing viscous force is not always attainable, especially in low permeability formations; hence decreasing the capillary forces through IFT reduction or wettability alteration is being used for many years. While in this paper, it is focused on pore structure alteration to reduce the capillary forces. An efficient chemical solution is introduced as a slow-reacting treatment agent to change the pore structure of damaged zone around the wellbore or around the hydraulic fractures where the effective permeability of porous media is significantly impaired due to the phase trapping. The impacts of the treatment on rock pore structure and the resulting capillary forces were evaluated at both pore and core scale. The effective permeabilities of tight carbonate rocks were measured before and after phase trapping damage and after the treatment at HPHT conditions. In addition, the feasibility of field application of the new treatment technique was investigated by compatibility and corrosion testing. It is found that the treatment solution is reacting with rock minerals at very slow rate such that it can penetrate deeper into the formation before it is spent. It is shown that the active ingredient can be dispersed into the aqueous wetting layer, enlarging the pore body and pore throats by rock dissolution. The results from the coreflood testing showed that the capillary reduction is effective enough to reduce the trap phase saturations and enhances the effective gas permeability significantly (up to 400%). It is concluded that this capillarity reduction (due to the pore enlargement) occurs with greater extent at the region near to the wellbore where the highest phase trapping is reported. When the high concentrated solution was injected, zero capillary zone was also achievable. It is also verified that the treatment solution is fully compatible with typical formation brines and the corrosion rate is far below the accepted corrosion level of 0.05 lb/ft 2 . Finally, from the cost-analysis results, it is shown that this new treatment is comparable to the solvent/surfactant injections while it benefits from its longevity and lower operational risks. The new treatment method proposed here is cost effective and experimentally proven to be efficient and long-lasting. Such chemical treatment is recommended to alleviate gas flow in tight gas with aqueous trapping damaged zone or in gas condensate reservoirs with condensate banking problem.

For many unconventional reservoirs, the initial oil saturation is extremely low (around 30 %). In such circumstances, it is necessary to use alternative geological and hydrodynamic simulators to forecast production levels. A novel adaptive modeling approach based on cascades of fuzzy logic matrices was proposed and implemented for a mature carbonate oil reservoir in the Permian basin of Texas where next generation waterflooding was considered to revive development process and increase oil recovery. The proposed approach is a variant of machine learning to solve the classical analysis and synthesis problem. At the analysis stage, the input and target parameters are normalized in order to equalize their significance. For each pair of input parameters, a fuzzy-logic matrix is formed and populated with actual values of the target parameter. The set of matrices forms a cascade in which every component is characterized by its own membership function. At the synthesis stage, forecasted results of the target parameter are calculated taking into account all membership functions and correspond to the maximum values of their superposition. By means of the proposed approach, geological and hydrodynamic models of the unconventional reservoir were successfully created, which made it possible to estimate the distribution of its initial and remaining oil reserves for all reservoir formations. The options for further reservoir development were also considered including the reactivation of non-operating wells, drilling new wells, and initiation of waterflooding. The obtained results confirmed that waterflooding was able to enhance the cumulative oil production of the reservoir compared with the base case without waterflooding, and its role became more significant as the number of operating production wells increased. The calculated results also showed that the proposed approach was quite sensitive to the changes of input parameters, for example, to the number of production and injection wells. The cumulative oil production varied several times depending on the considered option. The calculated results justified the ability of the proposed approach to forecast the development results and to choose the proper strategy for the reservoir reviving. A distinctive feature of the proposed approach was its ability to adapt to any of geological and field conditions, such as the extremely low initial oil saturation that most reservoir simulators do not take into consideration.

The poor volumetric sweep efficiency for secondary and tertiary oil recovery processes is mainly caused by reservoir heterogeneity, whether sandstone or carbonate reservoirs. Reservoir heterogeneity is usually characterized by permeability anisotropy and permeability contrast of the formation. Because of the problems of permeability anisotropy and permeability contrast of low and high permeable zones, most of displacing agents are injected into the high permeable zone. When the displacing agent is produced from production well, the displacing efficiency is extremely ineffective. In other words, large quantities of oil remain in the low permeable zone, which is un-swept by displacing agent. In this study, we used In-Situ sc-CO 2− Emulsion as a conformance control agent to plug the high permeable zone, and then improve the volumetric sweep efficiency of the low permeable zone in a carbonate formation. To achieve this goal, we studied the effect of two types of conformance control patterns on tertiary oil recovery performance by sc-CO 2 miscible injection for carbonate reservoirs at reservoir conditions. The conformance control patterns are classified as follows: (1) isolated the low permeable zone and opened the high permeable zone, and (2) opened both the low and high permeable zones when a base-gel system was injected into the core plugs after initial sc-CO 2 flooded. Two physical models consisted of carbonate core plugs set up initially to carry out the core flooding experiments of displacing oil and obtained the remaining oil saturation by water flooding as a secondary oil recovery process. The preliminary sc-CO 2 injection was conducted following water flooding to recover the remaining oil after water flooding as a tertiary oil recovery mode. The practice of the conformance control patterns using In-Situ sc-CO 2− Emulsion generated by injecting base-gel system into the core in which had the presence of sc-CO 2 was performed after the preliminary sc-CO 2 injection. The second sc-CO 2 injection was conducted following base-gel system injection. All experiments were under reservoir conditions. The base-gel system used in this study consisted of polymer and surfactant. The experiments of stabilization and apparent viscosity measurement of the base-gel system and CO 2 emulsion were conducted at varying experimental conditions. Based on the results and observations of the characteristics of study on the base-gel system and CO 2 emulsion, core flooding experiments, the practice of the conformance control patterns with in-situ sc-CO 2− Emulsion, and second sc-CO 2 miscible injection, the in-situ sc-CO 2 emulsion was generated successfully in the formation in which was the presence of sc-CO 2 . The volumetric sweep efficiency and oil recovery under the conformance control patterns using in-situ sc-CO 2 emulsion was improved for both physical models. Also, the production performances were compared for both physical models before and after base-gel system injection in this paper.

The purpose of surfactant-polymer (SP) formulation design is to concurrently achieve ultra-low interfacial tension and good mobility ratio. To this respect, associative polymers were found to be particularly interesting since their use could simultaneously solve demixing issues that can be observed in bulk when mixing surfactants with standard partially hydrolyzed poly-acrylamide (HPAM) polymers, and enhance the mobility ratio when injected in confined and under flow conditions. Varying the brine salinity and the polymer chemistry (either HPAM or associative polymer) with the same surfactant system led to the definition of four SP compatibility cases, on the basis of phase diagrams. First the focus was specifically directed to bulk and kinetic studies based on viscosity, cryo-TEM and turbidity versus time measurements. Then, monophasic injections were performed in a coreflood rig with a 3D outcrop rock with the designed formulations. The mobility reduction entailed by the injected solutions was measured by monitoring the pressure drop along the core. With the HPAM polymer, an increase in salinity leads to a clear degradation of the SP compatibility or even to a demixing behavior after a couple of days, due to depletion interactions. Interestingly, when the same surfactant system is mixed with the associative polymer, the demixing behavior vanishes due to a synergetic interaction between the surfactant and the associative polymer, hence changing the overall physical structure of the SP system and leading to a crystal clear formulation. Regarding monophasic injections in coreflood, as expected the compatible SP formulations designed at low salinity led to excellent in-depth transport properties with both polymers. While demixing at high salinity, the SP formulation involving HPAM showed good transport properties since the mobility reduction stabilizes at a value close to the relative viscosity of the solution. More interestingly, the mobility reduction for the SP formulation integrating the associative polymer also reaches a plateau but with a value almost five times higher than its relative viscosity. These results highlight that the use of an associative polymer instead of a conventional HPAM in a SP formulation can present the double advantage of vanishing depletion interactions in bulk, hence improving the formulation's solubility, and enhancing the developed mobility reduction in a coreflood experiment. It has been proven that associative polymers can bring a solution to SP compatibility issues by vanishing depletion interactions and hence improving the formulation's solubility. Depending on the surfactant formulation involved, the addition of an associative polymer can drastically enhance the developed mobility reduction while decreasing the polymer concentration compared to the use of a conventional HPAM polymer. This dosage reduction is also an element of economic advantage in favor of associative polymers.