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Collaborating Authors
Barmer Hill Formation
Horizontal Sucker Rod Pumping Wells โ Novel Unconventional Dyna Card Signatures Interpretation for Pump & Rod Run-life Optimisation
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Jadhav, Sujit (Cairn Oil & Gas, Vedanta Ltd) | Manish, Kumar (Cairn Oil & Gas, Vedanta Ltd) | Chandak, Ravi (Cairn Oil & Gas, Vedanta Ltd) | Negi, Avdesh (SLB) | Jha, Ajay (SLB) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd)
Abstract This paper presents a comprehensive and pioneering analysis, exploring the hitherto uncharted terrain of newly discovered dyna-card signatures and learnings associated with their analysis. These signatures, emblematic of an intricate interplay between high-deviation, azimuth, Dog-Leg Severity, and rod-guide application in horizontal-well configurations, constitute a novel dimension in the pursuit of optimizing pump and sucker-rod run-life. The emergence of these distinct dyna-card signatures unveils a paradigm shift, transcending the boundaries of convention by redefining the landscape of artificial lift systems. These signatures, while intricately linked to the complex conditions of horizontal-well operations, are conspicuously absent from the annals of existing literature. So, this paper will fill the gaps of theory & literature. By methodically delving into the core of these unconventional signatures, this paper embarks on an intellectual journey that transcends the known boundaries of understanding. This journey traverses through a comprehensive examination of not only the novel dyna-card signatures but also a spectrum of both rare and common dyna-card signatures. The outcome of this analytical odyssey is a revelation of strategies that cast light on the path to bolstering the longevity and efficacy of rod-string and pump performance. These novel & unconventional dyna-card signatures are connected with the challenges posed by elevated wear rates of rod-couplings and rod-guides, particularly where they interface with the tubing-wall, the paper introduces an arsenal of specialized rod-string designs to overcome these problems identified by the specialized dyna-card signatures. These designs, forged at the intersection of innovation and necessity, stand as a testament to the commitment to harnessing newfound knowledge in a practical manner.
- North America > United States (0.93)
- Asia > India > Rajasthan (0.28)
- North America > United States > Mississippi > Improve Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Bhagyam Field > Barmer Hill Formation (0.99)
- (4 more...)
Abstract Drilling long horizontal sections of directional wells are always challenging due to wellbore stability, hole cleaning, penetration and lubricity challenges. To overcome these troubles, Non-Aqueous Fluids (NAF's) are commonly used and fluid loss control is one of the key essential property that can affect the success of the drilling operation. Globally, conventional powders such as uintaite, grahamite or amine treated lignite are the commonly used fluid loss controlling agents in NAF's due to their ready availability and apparent economic posture. The enhancement in wellbore stability and lubricity as well as reduction in differential sticking, mud losses, and formation damage can be directly influenced effective by fluid-loss control and quality of filter cake properties. There are two major factors that limit the usage of powders. First, environmental concerns related to fluid's toxicity or biodegradation issues. Industry perception is strong that any asphaltic-based additives are detrimental if discharged into a marine environment. Whilst actual tests to validate this perception may be sparse, more operators are choosing the safe option of apparently costlier solid polymeric filtrate loss reducers. The second key aspect is the potential for formation damage through the solids invasion that occurs during dynamic fluid circulation while drilling before the filter cake is formed. The formation of an impermeable external filter-cake is considered essential for minimizing formation damage, and this should take place as soon as the reservoir rock is penetrated. Once the filter cake is established, the filtration process is controlled by the cake itself rather than by the rock. The design of a polymeric liquid fluid loss controlling agent is specifically to minimize the formation damage caused by the presence of solids in non-aqueous fluid and to improve the filtration properties with minimal additions when compared to conventional powder treatments. Reduced solids content in the mud helps in minimizing the potential for damage, which consequently has benefits in enhancing the production, by minimizing the solids invasion into the formation. No incompatibility issues were observed with either mineral or synthetic base fluids and the performance of the material was unaffected by temperatures up to 350หF. The polymeric liquid fluid loss controlling agent functions synergistically with other additives to tighten the fluid loss at significantly lower concentration levels, than would have otherwise been required with traditional asphaltic powders, without negatively influencing the rheological properties of the mud. Another benefit is, No screened out from the mud on shaker screens unlike the powdered material. This paper reviews the effectiveness of the newly developed polymeric liquid fluid loss controlling agent both in the lab and the field. A case history of successfully drilled wells are discussed with challenges overcome in those fields.
- Asia (0.68)
- South America > Brazil (0.46)
- Europe > Netherlands (0.28)
- Geology > Mineral (0.67)
- Geology > Rock Type > Sedimentary Rock (0.50)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Subsurface Injection Monitoring in Complex Geologic Media Using Pathline, Source Cloud and Time Cloud
Li, Ao (Texas A&M University, College Station, Texas, USA) | Chen, Hongquan (Texas A&M University, College Station, Texas, USA) | Jalali, Ridwan (Saudi Aramco, Dhahran, Saudi Arabia) | Al-Darrab, Abdulaziz (Saudi Aramco, Dhahran, Saudi Arabia)
Abstract Monitoring of subsurface fluid motion is critical for optimizing hydrocarbon production and CO2 sequestration. Streamlines are frequently employed to visualize fluid flow; however, they provide only an instantaneous snapshot of the velocity field and do not offer an exact representation of fluid movement under varying field conditions. In contrast, pathlines are constructed by tracking individual particles within the fluid, enabling us to trace the movement of these particles as they traverse through changing velocity fields. This paper presents the development and application of pathlines for flow visualization in complex geologic media. The flow visualization is further aided by source cloud (streak lines) and time cloud (isochrones representing moving fluid fronts). We demonstrate the power and utility of the developed tool in fractured media using Embedded Discrete Fracture Model (EDFM). Pathlines track the history of flowing particles in the reservoir. Pathlines can be spliced from streamline segments over time, tracing the trajectory of a particle under changing velocity fields. For each interval, a pathlineโs end is extended with a streamline segement whose elapsed time of flight (TOF) equals the time interval. Based on the pathlines, streaklines and timelines can also be visualized. Streakline is formed by all fluid particles emitted at the same location. Timeline is the contour formed by all fluid particles emitted at the same instant and represents the fluid front movement. In 3D, these two concepts are more generally visualized in groups of points rather than lines, so we refer to them as source cloud and time cloud. The proposed injection monitoring methods - Pathline, Source Cloud and Time Cloud - are tested using a 3D field-scale model with complex geologic features to demonstrate its power and utility. The pathlines were compared with streamlines, time of flight and the water saturation distribution. Three scenarios are tested: a constant well schedule, a changing well schedule with shut-ins, and a changing well schedule with fully injection cease. Results indicate that the pathline provides more accurate swept volume, consistent with saturation distribution. The robustness of our algorithm and implementation is demonstrated with a complex Embedded Discrete Fracature Model (EDFM) with non-neighbor connections to visualize flow patterns in discrete facture network. Pathlines display the fluid flow across fractures and are subsequently used to examine the sweep efficiency and the well connectivity.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > Texas (0.28)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Effects of Nano-Confinement and Heat Transfer on Phase Transition and Multi-Component Diffusion of CO2-Hydrocarbons During the Flowback and Early-Production Stages: A Field Example from a Liquid-Rich Shale Volatile Oil Reservoir
Jia, Zhihao (China University of Petroleum-Beijing, China) | Cheng, Linsong (China University of Petroleum-Beijing, China) | Cao, Chong (China University of Petroleum-Beijing, China / Sinopec Petroleum Exploration and Production Research Institute, Beijing, China) | Cao, Renyi (China University of Petroleum-Beijing, China) | Jia, Pin (China University of Petroleum-Beijing, China) | Pu, Baobiao (China University of Petroleum-Beijing, China) | Xue, Yongchao (China University of Petroleum-Beijing, China) | Ma, Ming (The Pennsylvania State University, United States)
Abstract Phase transitions of CO2-Hydrocarbons in liquid rich shale (LRS) volatile oil reservoirs after the CO2 pre-pad energized fracturing is quite obvious, particularly due to the impact of temperature changes and nano-confinement. In this paper, the impact of phase transitions caused by heat transfer and nano-confinement effects on the CO2 effective diffusion coefficient (CO2-EDC) after CO2 pre-pad energized fracturing was investigated. A novel multi-component diffusion model incorporating both heat transfer and nano-confinement effects was proposed to accurately evaluate CO2-EDC in the Gulong LRS volatile oil reservoir located in the Songliao Basin, China, which provides valuable insights into fracturing design and CO2-EOR in shale oil reservoirs. Firstly, the nano-pore network model (PNM) was constructed based on focused ion beam scanning electron microscopy (FIB-SEM). Secondly, components of oil samples were analyzed by chromatographic experiments. Then, the temperature in each pore-throat was calculated using Fourier heat transfer equations. In addition, phase states (liquid or vapor) of CO2-hydrocarbons in each pore-throat were determined by the modified PR-EOS considering nano-confinement effects, and diffusion mechanisms (Knudsen, Transition, Maxwell-Stefan diffusion) were determined by the Knudsen number. Finally, the novel PNM with multi-scale diffusion equations was established to calculate the molar flow rate, which is used to obtain CO2-EDC by solving Fick's law. The phase behavior of CO2-hydrocarbons in the nano-confined pores was investigated, and the CO2-EDC was calculated under reservoir conditions (137.5 โ, 37 MPa), and at varying injection temperatures. The results show that three distinct phase behaviors considering nano-confinement effects were observed under reservoir conditions: volatile oil in pore-throats larger than 33nm, condensate gas in pore-throats ranging from 5nm to 33nm, and wet gas or dry gas in pores/throats smaller than 5nm. However, it is only liquid in each pore-throat without considering the nano-confinement effects. As temperature increased, the phase behavior of CO2-hydrocarbons underwent a gradual transformation from a liquid state to a state of vapor-liquid coexistence, and finally to a vapor state. The phase transition is proved by the observation of a 2-month single gas production period prior to oil-gas production and a rapid decline in GOR (from 3559.7 m/m to 318.5 m/m) followed by a period of stability in the Gulong LRS volatile oil reservoir. It is worth noting that the CO2-EDC increased significantly with the nano-confinement effects, rising by 896.96% from 0 โ to 300 โ compared to an increase of 10.31% without the nano-confinement effects. Specifically, the CO2-EDC increased slowly in the liquid-dominated stage (< 180 โ) and rapidly rose in the vapor-dominated stage (> 180 โ).
- Asia > China (1.00)
- North America > United States > Texas (0.47)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.83)
Estimation of Surface Production Rates in Electrical Submersible Pump Producing Oil Wells by Numerical Iterative Algorithm-Based Models
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Manish, Kumar (Cairn Oil & Gas, Vedanta Ltd) | Chandak, Ravi (Cairn Oil & Gas, Vedanta Ltd) | Chauhan, Shailesh (Cairn Oil & Gas, Vedanta Ltd) | Singhal, Joy (Cairn Oil & Gas, Vedanta Ltd) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd)
Abstract This paper is an addendum to SPE-200174-MS, which explains the deterministic Approach Towards Well Intervention Candidate Selection & quantification of Parameters in ESP & Jet Pump Wells. The purpose of this paper is to quantify liquid rates in ESP producer wells by estimating the hidden parameter which directly impacts the system production rates. These hidden parameters are the tubing inner wall deposition, deposition inside pumps leading to pump head reduction. These hidden variables make simple well modelling software production rate calculations incorrect. This paper describes facts related to the verification of the output model liquid rates with genuinely observed rates by surface well test units and calibrated multiphase flow meter which makes the overall modelling valid and correct. In ESP wells, the input parameters required by the model is pump intake pressure, pump discharge pressure, pump running frequency and surface THP which are generally available. The models described in SPE-200174-MS for ESP & Jet pump wells can compute 3 variables for 3 set of equations. This model gives surface liquid rates, tubing wall deposition, ESP pump wear (deposition inside pump). Other input parameters required in the model to run the iterations are well water cut, GOR (Gas to oil ratio), productivity index, and reservoir pressure. These models calculate surface production rates for well rates allocation & support in monitoring various wells performance. Its results have been verified by various surface well test units & calibrated multiphase flow meters. There are many advantages of this algorithm such as - Prediction & calibration of MPFMs (Multiphase flow meter data) at well pads, tubing deposition estimation (assists in planning of tubing scraping jobs by slickline unit, Coil tubing roto-jet wellbore cleanout or motor assisted scraper jobs in flowing well), ESP pumps wear estimation (assist in planning ESP wear treatment by chemical soaking/mechanical flushing operations). This paper gives a new approach for ESP wells production rates determination. It mentions various factors which affects the liquid rate of wells. Production restoration candidates are very easily identified using this model. This can be very useful where well testing frequency is less, well pad MPFM is not installed, or where there are frequent issues in MPFM. This work assists in determining various important parameters to monitor oil producer wells with electric submersible pump (ESP). The problems are associated to the fields that contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. It was observed that formation oil to water flooding had adverse mobility ratio and improve sweep efficiency, polymer flooding was adopted. As the Polymer flooding proceeded, polymer breakthrough in producer wells was observed. The major challenges faced in producer wells are polymer & scale depositions. This issue has surfaced in field due to polymer breakthrough in oil producers and mixing of produced polymer concentration in well fluid with scales, wax, or other bivalent ions. Major concerns due to polymer deposition included, fouling of artificial lift system, decrease of well uptime, ESP efficiency decrease. ESP is the major artificial lifts for the field, the surface liquid rate is one of the most important parameters which can address production decrease which may have been caused by any reason. Thus, a necessity was felt to address the issue by empirical based modelling which can quantify the same. The developed models are helpful and determines various surface liquid rate and other critical causal parameters in ESP well.
- North America > United States > Texas (0.68)
- Asia > India > Rajasthan (0.47)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
A Novel Hierarchical Global-Local Model Calibration Method for Deep Water Reservoirs Under Depletion and Aquifer Influence
Li, Ao (Texas A&M University, College Station, Texas, USA) | Alpak, Faruk Omer (Shell International Exploration and Production Inc., Houston, Texas, USA) | Jimenez, Eduardo (Shell International Exploration and Production Inc., Houston, Texas, USA) | Yeh, Tzu-Hao (Shell International Exploration and Production Inc., Houston, Texas, USA) | Ritts, Andrew (Shell International Exploration and Production Inc., Houston, Texas, USA) | Jain, Vivek (Shell International Exploration and Production Inc., Houston, Texas, USA) | Chen, Hongquan (Texas A&M University, College Station, Texas, USA) | Datta-Gupta, Akhil (Texas A&M University, College Station, Texas, USA)
Abstract An ensemble of rigorously history matched reservoir models can help better understand the interactions between heterogeneity and fluid flows, improve forecasting reliability, and locate infill-drilling opportunities to support field development plans. However, developing efficient calibration methods for complex, multi-million cell deep-water models remains a challenge. This paper presents a hierarchical global-local assisted-history matching (AHM) approach with new elements, applied to a complex deep-water reservoir. The new AHM method consists of two stages: global and local. In the global stage, the reservoir energy is matched using an evolutionary approach to calibrate the model parameters with build-up and average reservoir pressures. Instead of using regional/box multipliers, we use parameters that are in line with geologic and engineering data across the reservoir. In the local stage, local updates are made to reservoir heterogeneity to match water cut in a geologically continuous manner. The permeability field is calibrated to production data using a novel streamline-based sensitivity-driven AHM method to ascertain the spatial variability and geologic continuity of local updates. The sensitivity for each streamline is weighted by the water fraction and constrained by a time-of-flight cutoff to focus on water intrusion regions within the near wellbore region. The resulting method is physically intuitive and easy to implement in practice. The hierarchical AHM method is field-tested in a complex deep-water reservoir. Associated challenges from model-calibration perspective are multiple saturation-function/PVT regions, uncertain sand connectivity, multi-sand well penetrations, a long reservoir history, and depletion-driven recovery under the influence of an aquifer. The method is applied to match data including build-up/reservoir pressures, oil production rates, and water cut. The evolutionary approach generates an ensemble of models with well-matched oil production rates and build-up/reservoir pressure using global model parameters. Local updates using streamline-based gradients are then conducted to match the water cut for each ensemble member while maintaining overall pressure match quality. Results show that the hierarchical AHM method significantly reduces the data misfit and is well-suited to primary recovery in a deep-water setting with few producers and under the influence of mild/weak aquifers. The new developments in the local stage make the entire workflow more robust because ensuing variations do not disrupt the global match quality for problems without a strong coupling between pressure and saturation physics. The novelty of the proposed method lies in the streamline-based sensitivity computation method modified for use in history matching deep-water reservoirs undergoing depletion under mild/weak aquifer influence. Using a two-stage global-local AHM workflow, the proposed method is robust, efficient, and straightforward to implement and deploy.
- Asia (0.93)
- North America > United States > Texas (0.47)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > License P2501 > Block 3/29a > Rhum Field > R2 Well (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > License P2501 > Block 3/29a > Rhum Field > R1 Well (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Search (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Evolutionary Systems (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Optimization (0.93)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.93)
Summary At the Milne Point polymer flood (North Slope of Alaska), polymer retention is dominated by the clay, illite. Illite, and kaolinite cause no delay in polymer propagation in Milne Point core material, but they reduce the effective polymer concentration and viscosity by a significant amount (e.g., 30%), thus reducing the efficiency of oil displacement until the full injected polymer concentration is regained [which requires several pore volumes (PVs) of throughput]. This work demonstrates that polymer retention on illite is not sensitive to monovalent ion concentration, but it increases significantly with increased divalent cation concentration. The incorporation of a small percentage of acrylamido tertiary butyl sulfonic acid (ATBS) monomers into hydrolyzed polyacrylamide (HPAM) polymers is shown to dramatically reduce retention. The results are discussed in context with previous literature reports. Bridging adsorption was proposed as a viable mechanism to explain our results. Interestingly, an extensive literature review reveals that polymer retention (on sands and sandstones) is typically only modestly sensitive to the presence of oil. Extensive examination of the literature on inaccessible pore volume (IAPV) suggests the parameter was commonly substantially overestimated, especially in rock/sand more permeable than 500 md (which comprises the vast majority of existing field polymer floods).
- Asia > Middle East (1.00)
- North America > United States > Texas (0.68)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Caspian Sea > Precaspian Basin > Kalamkas-More Field > Kalamkas Field (0.99)
- (5 more...)
Learning from Water Injection Pilot in a Low Permeability Reservoir Developed with Hydraulically Fractured Horizontal Wells โ ABH Field Case Study
Singh, Ranjeet (Cairn Oil & Gas, Vedanta Ltd) | Agarwal, Prashant (Cairn Oil & Gas, Vedanta Ltd) | Saurav, _ (Cairn Oil & Gas, Vedanta Ltd) | Gupta, Sumit (Cairn Oil & Gas, Vedanta Ltd) | Mandapati, Suresh Kumar (Cairn Oil & Gas, Vedanta Ltd)
Abstract Aishwariya Barmer Hill (ABH) is a Porcellanite oil reservoir located in the northern part of Barmer Basin in India. The formation has low permeability of ~1mD, an average porosity of 25% and has in-situ oil viscosity of ~3 cP. The ABH field has been developed with long horizontal wells with multistage hydraulic fracturing under depletion drive. The current estimated RF is 10-12% on depletion drive. To improve the RF, water flood was evaluated as the next stage of development. This paper discusses the results of water injection pilot within a complex setting with hydraulically fractured producer (observation) wells and impact of injection below and above frac pressure. Two short term injectivity tests and one long term injection pilot have been conducted in ABH field. Concepts like injection above and below frac pressure and injection in a hydraulic fractured well and a non-hydraulic fractured well were tested. The long-term injection pilot comprised of a vertical injector and two hydraulically fractured horizontal producers on it's either side. As the injection pressure was above frac pressure, data like time lapse Pressure Fall Offs (PFOs) was acquired to understand waterflood induced frac parameters. Production logging and bottom-hole pressure surveys were also conducted to understand injection profiles. Minimal injectivity was attained below frac pressure but good injectivity with sustained rate was observed above it. PTA analysis shows that fractures are induced due to water injection and time lapsed PFOs were analyzed to estimate the induced fracture parameters. Some unique signature of frac closure was also observed in PTA. Increase in water cut of one of the producer well was observed, however most of the injected water was getting imbibed into the reservoir. Role of injection water quality was also evaluated which may cause drop in injectivity and continuous frac growth. Numerical simulation was carried out to history match the observed injection performance. This indicated changes in effective permeability during injection and shut-in periods. Careful consideration of injection pressure, well design and pattern selection is critical for designing water flood in a low permeability reservoir with hydraulically fractured wells and this pilot was able to answer many questions related to it. The pilot suggested that below frac pressure injection may be required in on-trend well pattern. Poor quality injection water can cause growth of induced fracture. Response time on producer is a key consideration impacting project economics. Improving recovery from tight field development is a key area of focus and ABH pilot results will help to understand /solve some of the key considerations related to it.
- North America > Canada (1.00)
- North America > United States > Texas > Midland County (0.69)
- Asia > India > Rajasthan (0.66)
- (4 more...)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.82)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (37 more...)
Abstract Back-produced polymer to surface facilities is a significant topic in the literature due to the specific properties of the polymer, which are beneficial in the effective displacement of oil in the reservoir but could give challenges in the producers and surface facilities. This literature review addresses the impact of polymer on the key components of the production facilities ranging from artificial lift to the oil refinery and produced water disposal or reuse. The main polymer properties to interfere are (1) the ability to increase the viscosity of the produced water and (2) the precipitation of the polymer with constituents in water or process chemicals. These two properties could cause equipment failure, off spec quality of the oil and water, leading to oil deferment and increased maintenance. The magnitude of these challenges depends on the level of back-produced polymer. From the literature it is difficult to diagnose at what polymer concentration, insignificant impact is observed and when the production issues begin. It is recommended to analyse each key component individually and assess at what polymer concentration impact is expected in the operations. Important to identify is that an optimal polymer selection for the subsurface reservoir, might not be the right choice for the production facility. Therefore, early involvement of surface and chemical engineers is crucial to a successful polymer flood. This review will discuss a selection of the available literature addressing the main challenges and showing several examples. The content of a monitoring plan is discussed as well as the critical & additional analysis are given to properly understand the production side of a polymer flood and assist with mitigation strategies.
- Asia > Middle East (1.00)
- Europe > Austria (0.93)
- North America > United States > Texas (0.68)
- Asia > China > Heilongjiang Province (0.46)
- Research Report > New Finding (0.93)
- Overview (0.68)
- Geology > Mineral (0.67)
- Geology > Geological Subdiscipline (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (8 more...)
Abstract The presence of solids in the hydrocarbon treatment and separation equipment downstream the choke can have a great impact on the process operability, assets risks, flow assurance, thus on the economics of the operation. It has been well documented that solids can highly stabilize emulsions, sometimes even better than surfactants. In fact, solids can be attached to the oil/water interface in an almost irreversible way that impedes droplets coalescence mainly by steric repulsion. Moreover, naturally surfactant molecules present in the crude oil (e.g., asphaltenes, naphthenic acids, resins, carboxylic acids) or production chemicals (e.g., anticorrosion, antiscales, demulsifiers, antifoamers) can enhance the ability of solids to promote emulsification and emulsion stability. In addition, the interaction of chemical EOR with the produced solids can lead to production issues like wellbore blockage, emulsion stabilization, increase of waste streams, equipment clogging, and so on. In this work, the impact of solid particles on oil/water separator (i.e., emulsion stability) and on the produced water treatment has been studied. On the one hand, the impact of the solid concentration has been evaluated through rapid emulsification tests founding that, as a general trend, the increase of the solid concentration led to more stable emulsions. The impact of the presence of polymer (Xanthan) has also been tested through bottle testing. The interaction between the solids, the polymer, the demulsifier, and the fluids is quite complex as their presence either has no impact or hinders separation. Furthermore, the solid partitioning between both phases depends on their size and wettability, leading in some cases to the formation of rag layers. On the other hand, the impact of these solids on different techniques of water treatment in presence of polymer has also been evaluated such as water clarification (gravity settling) in presence of water clarifiers or dead-end filtration. In the first case, the presence of solids enhanced water clarification either by enhancing agglomeration or by increasing the droplet density. In the case of the filtration, the main factor affecting the filtration is the polymer itself while the presence of the solid particles can enhance this behavior.
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- (3 more...)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- (2 more...)