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This paper presents a case history of scale treatments performed in a well producing in the North Sea. Kvitebjørn is a gas and condensate producer with high reservoir pressure (480bar) and high temperature (152°C). Well A-7 T2 started production in January 2014 and has a history of a carbonate scale precipitation.A few months after start-up, formation water breakthrough was observed in addition to a reduction in Production Index.
Due to challenges with removing scale by wireline, interventions using scale dissolver were performed in late 2017 and early 2018. The second dissolver treatment was followed by a scale squeeze to protect the well from further scaling. The chemicals used were qualified according to the Operator’s technical specifications. Due to high reservoir temperature, thermal stability was vital in the qualification process. The formation permeability was moderate, which was important to consider when evaluating the risk of formation damage.
The environmental category for the chemicals versus their performance was an important factor in the qualification process. Modelling programs were used to assess placement distribution under various bullhead pumping conditions. For the scale squeeze, a modelling program was used to simulate treatment lifetime using isotherms derived from laboratory core flood testing.
Water samples were taken from the well and analysed onshore in the supplier’s laboratory. Following the scale squeeze, water samples were taken from the well during the entire treatment lifetime. Ion concentrations and residual inhibitor concentrations were monitored together with production parameters to assess the scale situation in the well.
Following the treatments, the well showed an increased gas production. The well produced 1.2MSm3 at 40% choke before the treatments and 1.2MSm3 at 6-7% choke after. Laboratory work combined with field experience from this first well that was treated, forms the basis for possible future treatments. Being able to treat wells through pro-active and efficient scale inhibitor squeeze treatments will allow for continued production of wells exposed to scale risk, avoiding the cost and risks associated with mechanical scale removal and avoiding production deferral associated with potential dissolver jobs.
The production of high salinity brines (Total Dissolved Solids (TDS) > 250,000 ppm) during oil and gas production is known to cause severe scaling issues. When high TDS conditions are coupled with high concentrations of dissolved iron in a produced water, the challenges for controlling scale deposition increase significantly. The formation of the more common mineral scales (barium/strontium sulfate, calcium carbonate, and calcium) is expected in these produced waters and often other challenges associated with high TDS brines include the propensity for halite (sodium chloride) deposition to also occur in these environments as well. The elevated iron content present in these brines not only introduces the potential for deposition of iron-related scales but is also known to have a negative impact on scale inhibitor performance against calcium carbonate and barium sulfate scales. However, the impact on the inhibitor is different for both types of scale. The objective of this work is to evaluate the performance efficiency of polymeric and phosphonate-based scale inhibitor blends under both static and dynamic testing conditions using a synthetic brine with high TDS and varying concentrations of dissolved iron (up to 250 ppm).
The synergistic effects of combining these chemistries will be evaluated for this work. Dynamic Scale Loop (DSL) and static bottle testing will be used to determine the performance the efficiencies of the developed products.
When tested individually under a mixed scaling scenario with a high TDS and high iron containing brine, the scale inhibitors selected for this study had performance efficiencies (MED) values of 200 ppm or greater. However, when polymer/phosphonate scale inhibitor blends were evaluated a significant improvement in performance efficiency was observed.
This paper will give a detailed account of testing conducted to identify inhibitors capable of preventing the deposition of calcium carbonate and iron-related scales in challenging environments by utilizing the synergistic effects of the scale inhibitor chemistries.
Semin, Leonid (Schlumberger) | Belyakova, Ludmila (Schlumberger) | Isayev, Vadim (Schlumberger) | Velikanov, Ivan (Schlumberger) | Bannikov, Denis (Schlumberger) | Tikhonov, Alexey (Schlumberger) | Idimeshev, Semen (Schlumberger) | Kovalevsky, Oleg (Schlumberger) | Oussoltsev, Dmitry (Schlumberger)
We introduced fracture hydrodynamics and in-situ kinetics model capable of simulating particle size distribution of propping agent.
M. Faskhoodi, Majid (Schlumberger) | Damani, Akash (Schlumberger) | Kanneganti, Kousic (Schlumberger) | Zaluski, Wade (Schlumberger) | Ibelegbu, Charles (Schlumberger) | Qiuguo, Li (Schlumberger) | Xu, Cindy (Schlumberger) | Mukisa, Herman (Schlumberger) | Ali Lahmar, Hakima (Schlumberger) | Andjelkovic, Dragan (Schlumberger) | Perez Michi, Oscar (Schlumberger) | Zhmodik, Alexey (Schlumberger) | Rivero, Jose A. (Schlumberger) | Ameuri, Raouf (Schlumberger)
To unlock unconventional reservoirs for optimum production, maximum contact with the reservoir is required; however, excessively dense well placement and hydraulic fractures interconnection is a source of well-to-well interaction which impairs production significantly. The first step to have successful and effective well completion is to understand the characteristics of the hydraulic fractures and how they propagate in reservoir. This paper demonstrates an integrated approach with a field example in the Montney formation for how modern modeling techniques were used to understand and optimize hydraulic fracture parameters in unconventional reservoir.
Advanced logs from vertical wells and 3D-seismic were used to build an integrated geological model. Lamination index analysis was performed, using borehole imagery data to account for interaction of hydraulic fracture with vertically segregated rock fabric and to provide additional control on hydraulic fracture height growth during modeling process. A non-uniform Discrete-Fracture-Network (DFN) model was constructed. 3D-geo-mechanical model was built and initialized, using sonic log and seismic data.
Fluid friction and leak-off was calibrated, using treatment pressure and DFIT data. Hydraulic fracture modeling was done for pad consists of 6 horizontal wells with multi-stage fracturing treatments, by utilizing actual pumped schedules and calibrating it against microseismic data.
High-stress anisotropy led to planar hydraulic fractures despite presence of natural fractures in area. Fracturing sequence, i.e., effect of stress shadow, is seen to have major impact on hydraulic fracture geometry and propped surface area. Heatmaps were generated to estimate average stimulated and propped rock volume in section. It was also observed that rock fabrics, i.e., natural fracture and lamination has considerable impact on propagation of hydraulic fracture. Multiple realizations of natural fracture and lamination distribution were generated and used as an input in modeling process.
High resolution unstructured simulation grids were generated to capture fracture dimensions and conductivities, as well as track propped and unpropped regions in stimulation network. Dynamic model was constructed and calibrated against historical production data. History matched model was then used as predictive tool for pad development optimization and to evaluate parent-child interaction in depleted environment.
High angle S-shaped and high displacement L-shaped well profiles are preferred now-a-days in Balimara field located in the northeast region of India. Main targets are the deep Clastic reservoirs of Oligocene age. Major events reported are while drilling against dipping formations with differential stuck pipe situations with variety of drilling complications in the unstable formations owing to shales in Tipam sandstone and thin sections of coal and shale alteration in oil bearing Barail sandstone formation. The substantial risk of wellbore instability in accessing the reservoirs with lateral variation in pore pressure threatened the commercial success of the project. This paper elaborates how geomechanical information along with BHA design and chemicals was integrated into the decision-making process during well design and drilling operations to avoid wellbore instability issues.
Wellbore stability analysis through Mechanical Earth Model was conducted using estimated state of stress and mechanical properties of the overburden and reservoirs. The model incorporated data from several sources including geophysical logs, leak-off tests, advanced sonic far field profile and drilling records collected from the earlier wells. Examination of the deviated well bore profiles suggested occurrence of ledges due to lower mud weight and improper drilling parameters while drilling alternate layers of sand, shale and coal in Barail formation. Horizontal stress contrast increases in Barail formation supporting the need of higher mud weight with increased well deviation towards specific azimuth.
The integrated geomechanical analysis provided key information: The 9 5/8" casing shoe should be set at shale layer of Tipam Bottom to isolate upper differential sticking prone sandstone layers with Barail Argillaceous sequence. This will help to drill 12.25-inch hole with 9.6 ppg-9.8 ppg only. Shale layers at Tipam bottom require 10.0-10.5 ppg, while Barail shale requires 10.5 ppg-11.0 ppg for vertical well. When the well deviation increases up to 30deg, mud weight requirement rises to 11.2 ppg-11.8 ppg. Based on analysis, the mud weight at the start of 8.5inch section was raised sufficiently to 10.5 ppg to avoid the hole collapse experienced in the earlier lower angle wells. Later, continuous review of torque and drag along with cutting analysis helped to raise mud weight up to 11.0 ppg till well TD. As a result, lower UCS shale and coal layers are drilled with minimal shear failure and improved hole condition. However, changes to the mud system were needed to limit fluid loss and avoid differential sticking across the sandstone. For deviated section, rotary BHA has been used to improve hole trajectory vs. planned with lesser ledges. Downhole hydraulics has been maintained with proper flow rate and rpm to main hole cleaning. The new well engineered with the integrated geomechanics information has been drilled from surface to extended TD while saving 15 rig days.
In oil and gas industry it is crucial to have reliable information on well, reservoir and boundary types and properties. Detailed information can be extracted from a proper interpretation of pressure and rate transients of well testing data. Though, there are times that even with an in-depth pressure transient analysis, a unique solution on well, boundary and especially the reservoir types cannot be obtained and makes it difficult or even impossible to extract correct information. In this study deep learning (DL) is used to tackle this problem by differentiate possible reservoir models and select the most appropriate model based on pressure derivative response. Accuracy of the classification model on real field data with known models is also explored.
Reservoir models can be identified by measuring the downhole pressure data and analyzing the changes in trends in pressure curves and especially pressure derivative curves. In this study, different DL algorithms are used to identify the basic characteristics of pressure derivative curves to determine reservoir model. Several possible well/reservoir/boundary types are considered to select the best model that can be used for well/reservoir/boundary property estimation. Before feeding the networks, training data curves would be shrunk in size using wavelet transform (WT) which is able to sustain the pressure derivative features in a much-compressed form to accelerate algorithm training and testing.
The technique used in this work is a time-efficient process that learns important signatures of pressure derivative curves to classify reservoir models. Unlike the conventional well testing methods in which models are determined from the visual inspection of the pressure and pressure derivative plots, the technique used in this study was trained with a dataset consists of hundreds of reservoir models generated by solving diffusivity equation under different well, reservoir, and boundary conditions. The procedure was applied to multiple field examples with known reservoir model and reservoir properties and proved the consistency and flexibility of the methodology for true reservoir model selection. DL-based models also shown to be very handy with excellent computational efficiency especially when dealing with the complex patterns on the pressure derivative curves. The study showed that the method has great capability to classify pressure derivative and can also tolerate noise when applied on real pressure data.
Large dataset used in this study can increase the comprehensiveness of the training and test data sets. The big advantage of the DL-based approach was the improvement in the pattern recognition of the pressure derivative curves without the need of any feature handcrafting or any prior knowledge of well, reservoir, and boundary types. ML proved to be a reliable, fast, and accurate technique that can significantly improve the process of well, reservoir, and boundary type detection based on pressure derivative curves.
Malon, Ruslan (Independent) | Abbott, Jonathan (Schlumberger) | Belyakova, Ludmila (Schlumberger) | Pepic, Svetlana (NIS a.d. Novi Sad) | Kulakov, Vladimir (NIS a.d. Novi Sad) | Demenesku, Kosta (NIS a.d. Novi Sad)
Hydraulic proppant fracturing is one of the most effective tools to optimize production in the mature, low- permeability reservoirs found in the Pannonian Basin in Central Europe. Fracturing can effectively enhance production by improving reservoir contact, but for wells already producing with high water cut, even a small fracture extension into a water-bearing or "wet" zone offsets the gains in hydrocarbon production. Fracture geometry control (FGC) techniques limit increases in water cut, which is one of the greatest challenges to extending economic production and maximizing ultimate recovery for mature wells. Artificial barrier placement and proppant channel fracturing were proven to improve hydrocarbon production while fracturing stimulation targets adjacent to high water saturation intervals.
The pilot included candidates in thin, low-permeability sandstone reservoirs, located within 5 to 10 m of wet intervals. An integrated engineering approach to fracture height growth was applied, including a new proppant transport model to predict fracture geometry improvement using the FGC solution. The FGC solution consisted of injection of an engineered particulate mixture designed to bridge at the fracture edges and arrest height growth. Additionally, the bridging mixture provided reduced conductivity and acted as a fracture flow restriction for water. The FGC solution was also combined with channel fracturing in some trials as an attempt to reduce net pressure development, minimize the risk of height growth and improve fracture quality in the low-permeability reservoirs. The new engineering approach, incorporating the new solids transport simulator, enabled the successful implementation of the FGC technique in the pilot candidates. Fracture height control was achieved in absence of good geological barriers. The benefits of this new approach are supported by a consistent improvement in hydrocarbon production without an increase in water cut. In field A, the combination of FGC and channel fracturing resulted in additional production when compared to wells where only FGC was implemented. Evaluation of this pilot included a comparison with offset wells stimulated without this technique when a water cut increase was always observed in the field A.
This paper describes the first implementation of the complex technology and engineering solution to control fracture height for conventional wells in the Pannonian Basin. For the first time, the mixture of solids was modeled directly, and the influence on fracture geometry and production results is shown. The cases are of significant interest because of the global challenge of maximizing recovery from mature reservoirs with nearby water hazards. The application of a full engineering process for the design, placement, and evaluation of the fracture height control treatments provides an improved degree of confidence that such operations can result successful production optimization. The workflow as presented and applied is an effective tool to reduce risk of high water production when fracturing close to water contacts.
AL-Hajri, Nasser Fadghoush (PAAET) | Al-Khaldy, Ali Dawood (Kuwait Oil Company) | Hassan, Jassim Mohammed (Kuwait Oil Company) | Dashti, Reham Abbas (Kuwait Oil Company) | Kader, Mohamed Abdulmonem (Kuwait Oil Company) | Gupta, Satya Kumar (Kuwait Oil Company) | Al-Buloushi, Zainab Abdulkareem (Kuwait Oil Company) | Abdelbaset, Shady Moustafa (Schlumberger) | Siam, Mahmoud (Schlumberger) | Al-Hassan, Ahmed (Schlumberger) | Chang, Catherine (Schlumberger) | Ramadan, Zeyad (Schlumberger)
Umm Ghudair Field is one of the major oil producing fields in West Kuwait. Oil was discovered in 1962 in the Lower Cretaceous Minagish Oolite Formation and more than 200 wells have been drilled to exploit this reservoir since then. Stratigraphically, the formation is defined by three units; Lower, Middle and Upper. The lower and upper units are considered non-reservoirs, while the middle one is hydrocarbon bearing. However, because of the continuous production over the past 50 years, the filed started to show a variable rise in its oil water contact (OWC). Consequently, this uncertain OWC rise has impacted the planning and production of the newly drilled wells (deviated and horizontal). Several recently drilled wells showed water breakthrough much earlier than expected.
To address this challenge and with an attempt to proactively predict the current OWC depth in the new wells to be drilled, Kuwait Oil Company (KOC) decided to try the new High Definition Reservoir-Mapping-While-Drilling (HD-RMWD) technology in one of the horizontal well in their field. The objective was to assess the potential of the technology in detecting and mapping the current OWC while landing the well in the target. Due to the ultra-deep detection range of the technology (in excess of 200 ft), the landing point could be adjusted proactively and early enough to accommodate any unexpected OWC depth changes in the field.
Germik, a mature heavy oil field in Southeast Turkey, has been producing for more than 60 years with a significant decline in pressure and oil production. To predict future performance of this reservoir and explore possible enhanced oil recovery (EOR) scenarios for a better pressure maintenance and improved recovery, generation of a representative dynamic model is required. To address this need, an integrated approach is presented herein for characterization, modeling and history matching of the highly heterogeneous, naturally fractured carbonate reservoir spanning a long production history.
Hydraulic flow unit (HFU) determination is adopted instead of the lithofacies model, not only to introduce more complexity for representing the variances among flow units, but also to establish a higher correlation between porosity and permeability. By means of artificial intelligence (AI), existing wireline logs are used to delineate HFUs in uncored intervals and wells, which is then distributed to the model through stochastic geostatistical methods. A permeability model is subsequently built based on the spatial distribution of HFUs, and different sets of capillary pressures and relative permeability curves are incorporated for each rock type.
The dynamic model is calibrated against the historical production and pressure data through assisted history matching. Uncertain parameters that have the largest impact on the quality of the history match are oil-water contact, aquifer size and strength, horizontal permeability, ratio of vertical to horizontal permeability, capillary pressure and relative permeability curves, which are efficiently and systematically optimized through evolution strategy. Identification and distribution of the hydraulic units complemented with artificial neural networks (ANN) provide a better description of flow zones and a higher confidence permeability model. This reduces uncertainties associated with reservoir characterization and facilitates calibration of the dynamic model. Results obtained from the study show that the history matched simulation model may be used with confidence for testing and optimizing future EOR schemes.
This paper brings a novel approach to permeability and HFU determination based on artificial intelligence, which is especially helpful for addressing uncertainties inherent in highly complex, heterogeneous carbonate reservoirs with limited data. The adopted technique facilitates the calibration of the dynamic model and improves the quality of the history match by providing a better reservoir description through flow unit distinction.
Summary The common occurrence of massive methane hydrate in numerous gas-chimney structures, located in Joetsu Basin, Sea of Japan, has stimulated great interest in academia, industry, and national institutes to develop technologies that produce the potential energy resource. Unlike other deep methane-hydrate deposits in formations a few hundred meters below the seafloor (mBSF), the hydratechimney structures are at the seafloor or up to 100 mBSF; therefore, previously field-tested production methods such as depressurization are not applicable. In this work, we proposed a new potential production method of jetting from the openhole section of a wellbore to excavate the hydrate bearing. However, jetting will create large empty chambers below the seafloor and could possibly jeopardize the stability and safety of wellheads and the production facility on the seafloor. This paper presents a 3D geomechanical simulation study to evaluate the feasibility of the jetting method to produce methane from the hydrate chimneys in the Sea of Japan. Dynamic numerical simulation using a 3D finite-element simulator was conducted to simulate the jetting process to excavate a 16-m-diameter chamber from the bottom of the borehole (approximately 100 mBSF) progressively up to the bottom of the conductor of the wellbore, approximately 10 mBSF. The numerical simulation shows that jetting is likely to be feasible because all simulation cases resulted in tolerable vertical displacement and equivalent plastic strain under ideal conditions [e.g., lateral homogeneous formation, constant chamber pressure (equal to formation pore pressure), and blowout-preventer (BOP) weight of 20 tons]. In these cases, the plastic zone only extends to a limited area (10-20 cm) from the sidewall. Additional complexities were considered in the numerical simulation to evaluate the operational risks during actual jetting operations, such as faulting, fluctuation of chamber pressure, and change of BOP weights. This numerical simulation evaluated potential risks related to jetting operations of hydrate chimneys in the Sea of Japan and provided critical information for the engineering design of the proposed field test of jetting operations to produce this valuable resource in the Sea of Japan. Introduction Methane hydrate is an ice-like compound with gas molecules trapped in the cage of water molecules (Sloan and Koh 2008).