bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical Application on Mitigation of Formation Damage Induced by Gravel Pack Operations in Offshore Gas Condensate Field
Authors: Eldabbour Mohamed , Fadel Ayman , Soliman Ali , Safwat Hatem , Labib Amr , Belli Andrea , McLaughlin Ryan , Patey Ian T.M. , Munro Murdo S. , Jones David 
Published: October 2019

Abstract
Gravel pack completion operations are a sand production management technique that is considered successful if the well produces no sand and has minimal impact upon the potential productivity and hydrocarbon recovery. However, statistics show that many gravel packed wells suffer reduced productivity as a result of damaging mechanisms induced by gravel pack operations and completion fluids. This provides an opportunity for improved hydrocarbon recovery if the mechanisms are understood.
A study was conducted to simulate the alterations caused by the gravel pack operations including gravel carrier fluid, completion fluid and lost circulation material. Simulations using reservoir core samples were carried out at near-wellbore conditions, in order to examine operational fluid interactions with the reservoir and assess the impact of a stimulation fluid. Cores from a range of rock types were selected, and prepared to initial gas-leg saturation. An operational sequence consisting of completion fluid, gas production, stimulation fluid, completion fluid, and production of gas was carried out, with permeability measurements before and after the sequence.
In all core samples, the introduction of the completion fluid during gravel pack installation resulted in alterations of 30-60% reduction in core permeability. Geological interpretative analysis showed damage mechanisms including clay fines movement and pore blockage, dissolution of native cement, and retention of operational fluid in the pores. It was believed that retention of fluids was having the most significant impact upon permeability. Stimulations were carried out for all samples to quantify the effect of acid on removing the formation damage resulting from the gravel pack operations. The experiments showed 5-10% improvement on average except for one core sample, which showed 40% improvement.
Based upon the previous results, a modified sequence was examined, utilizing an alternative stimulation fluid/acid sequence and adding an extra operational stage. The experiments showed that after treatment an improvement of around 10% was noted, and after an additional stage, a further 8% improvement was seen. The final permeability was over 80-90% of the initial permeability, indicating that there was the potential for good productivity and recovery of hydrocarbons.
The results of the study were applied to seven gravel pack jobs in three wells and the field results showed the reduction in productivity after gravel pack installation was around only 10%, compared to previous wells which showed more than 50% reduction in productivity.
Optimization of Hydraulic Fracturing Design in Unconventional Formations: Impact of Treatment Parameters
Authors: Kolawole Oladoyin , Esmaeilpour Sajjad , Hunky Rabia , Saleh Laila , Ali-Alhaj Haiat K. , Marghani Mouna 
Published: October 2019

Abstract
Due to technical and economical limitations of hydrofracturing operations in unconventional reservoirs worldwide, an optimized hydraulic fracturing design is critical to achieve a successful well stimulation operation. The number and length of perforation clusters in each stage, proppant and fluid frac compatibilities, and optimum spacing, are some of the challenges inhibiting successful hydraulic fracturing operations across the world. In this study, we aim to investigate the effects of varying fracture-cluster lengths, proppant types and sizes, and frac fluid types, on hydraulic fracturing treatments using 2D and 3D simulation models. Our study relies on petrophysical log data, geologic data, well data, reservoir data, and production data from a well in the Eagle Ford shale formation. Firstly, we created stress log and developed a stress profile to determine fracture initiation location and orientation. We selected different combinations of frac-fluids and proppant types, 5 fracture-cluster lengths in a single stage, 2 different spacing lengths between fracture clusters, determined the maximum allowable treatment pressure, and selected an ideal fracture propagation model. Secondly, we selected an optimum treatment size, followed by performing the production forecast and the net present value analyses. In the third task, we determine the optimal specifications of the fracturing fluid and proppant, fluid volume and proppant weight, followed by creating a schedule for fluid injection and proppant mixing, and injection pressure profile prediction. Our results show that greater cluster lengths provide better and optimized hydraulic fracture treatment in some cases because of greater proppant coverage, fracture conductivity, stimulated reservoir volume (SRV), fracture half-length, and propped length. In the results obtained from varying proppant sizes and frac fluids in cases 2 and 3, we observed that Northern White 30-50 proppant produced a lower fracture conductivity (average of 2.0 md-ft) and fracture half-length (91 to 123 ft), in comparison with proppant composed of Badger 100 mesh and RC Sand PC 16-30, which achieved a greater fracture conductivity (&gt; 3.0 md-ft) and fracture half-length (129 to 148 ft). In the 3 cases we investigated, we observed that stress shadowing and interference hindered the growing fractures which eventually led to a collapse of some fractures. We believe that our preliminary study will provide valuable critical decision-making during hydraulic fracturing operations in various unconventional formations across the world.
Potential of Copper-Based Oil Soluble Catalyst for Improving Efficiency of In-Situ Combustion Process: Catalytic Combustion, Catalytic In-Situ Oil Upgrading, and Increased Oil Recovery
Authors: Yuan Chengdong , Mehrabi-Kalajahi Seyed Saeed , Sadikov Kamil , Varfolomeev Mikhail A. , Emelianov Dmitrii A. , Rodionov Nikolay O. , Amerkhanov Marat I. 
Published: October 2019

Abstract
In-situ combustion (ISC) is a promising thermal enhanced oil recovery (EOR) method for heavy oils. However, its field application is still limited due to difficulty in ignition, low combustion efficiency, unstable combustion front, etc. To improve the success rate of ISC process, we investigated the effectiveness of copper-based oil soluble catalyst for catalyzing combustion and in-situ upgrading of heavy oils.
High-pressure differential scanning calorimetry (HP-DSC) and TGA were used to investigate the effect of catalyst on the thermochemistry (onset temperature, temperature range of reaction interval, heat effect, etc.) and kinetic parameters of combustion process. A Porous medium thermo-effect cell (PMTEC) was designed to study the catalytic combustion of heavy oil in porous media under air flow. And, a visual combustion tube (VCT) was developed to study the catalytic effect of catalyst on the ISC process, including improving combustion front propagation, in-situ upgrading of heavy oils, and oil recovery.
HP-DSC results showed that copper-based oil soluble catalyst significantly shifted the low-temperature oxidation (LTO), transition stage (FD), and high-temperature oxidation (HTO) into lower temperature ranges. Especially for HTO, the end temperature was decreased about 120 °C. It was finished at a narrower temperature region with a higher heat flow, which implies that the combustion efficiency of HTO was greatly improved. TG-DTG data also showed the combustion reaction was transferred into lower temperatures. In addition, from TG-DTG and kinetic data, it can be concluded that the catalyst significantly reduced the activation energy in FD and HTO stage, which thus decreases the reaction barriers between FD and HTO and increases the continuity of reactions between FD and HTO.
PEMTC experiments also showed that the ignition temperature of heavy oil combustion in porous media in airflow was decreased about 46 °C by copper-based catalyst. VCT experiments indicated that in the presence of copper-based oil soluble catalyst, combustion front propagate faster, oil recovery was 10% higher than without catalyst, and a deep in-situ oil upgrading was achieved with a significant viscosity reduction (9 times lower) and increase of saturates content (especially alkanes with lower carbon number C11-C17). All these results showed that copper-based oil soluble catalyst has a great potential in improving the efficiency of ISC process and in-situ oil upgrading. Its application can help to improve the success rate and wide application of ISC process for heavy oil recovery, which will promote the highly efficient development of heavy oil resources.
Visual Analysis of SAGD with Chemical Additives
Authors: Huang Jingjing , Babadagli Tayfun 
Published: October 2019

Abstract
SAGD (steam assisted gravity drainage) has been proven as an effective technology to enhance heavy oil/bitumen recovery. The main shortcoming of this method is its inefficiency, a result of high water and energy consumption. As a solution to SAGD efficiency improvement, we propose the addition of chemicals resulting in higher recovery and reduced steam consumption. The objective of this paper is to screen new generation chemicals as additives and study the mechanisms and optimum injection strategies. This screening was achieved through Hele-Shaw type macroscopic visual experiments.
We previously screened a wide variety of chemical additives (Bruns and Babadagli 2017, 2018) for steam flooding. As a continuation of this work, these chemicals were tested for SAGD conditions using a new visual experimental design where the optimal injection strategies were identified, eventually providing a reference for the selection of chemical additives for field applications.
11 conventional and new generation chemical additives (heptane, biodiesel, DME, LTS-18, Tween 80, Span 80, Novelfroth 190, ionic liquid (BMMMIM BF4), silicon dioxide nanoparticle, DES9, and DES11) were selected based on both their strong thermal stability and enhanced oil recovery capability. The recovery improvement mechanisms for the different chemical additives and different injection strategies were identified through flow characteristics, emulsifying ability, viscosity reduction capability, and wettability alteration. Simultaneously, the mechanisms were studied from a macro perspective via analyzing areal sweep efficiency and microscopic oil displacement efficiency together with observing the images acquired during the process.
Three different injection strategies were applied for each chemical: (1) chemicals were injected at the beginning, (2) in the middle, and (3) at the end of the steam injection. The chemical additives played different roles in recovery improvement, and different chemical addition strategies yielded different mechanisms. Heptane exhibited extraordinary characteristics with maximum "steam saving" (34.52%) when the middle injection strategy was applied and maximum ultimate oil recovery (64.75%) was obtained for the end injection strategy due to the ability to reduce the viscosity of heavy oil by dissolving around the chamber edge. Steamflooding with Novelfroth 190 showed an excellent performance for the middle and end injection strategies due to its ability to develop rapid oil drainage "channels". The addition of surfactant LST-18 presented the ability to improve the EOR by forming emulsions. Additionally, the distributions of the steam chamber in the Hele-Shaw cell were different due to the changed flow characteristics when the same chemical additive was injected at different times, thus showing the ability to reduce viscosity and form emulsions with different strengths.
Management of Barium Sulfate Precipitation in Rich Iron and High pH Environment during Stimulation Operation
Authors: AlAamri Jamal , AlDahlan Mohammad 
Published: October 2019

AbstractThe quality of base fluid used in the preparation of different stimulation and wellbore cleaner recipes is very critical toward high efficient job. However, due to the limited access to adequate quality water sources, efforts to minimize the operational impacts of such less quality source is grown rapidly. High sulfate mixing water is well known example of such low quality water and which results in sulfates deposits during stimulation operation. In this paper, an effective management of barium sulfate precipitation in high pH and iron rich environment is presented.A simulated low quality water with high sulfate content of more than 500 ppm and produced water of high barium and iron contents were proposed and prepared for this study. Static jar compatibility tests at high pressure and temperature were conducted at different ratios to study the potential precipitation of sulfates and iron deposits. Precipitated solids were identified by Scanning Electron Microscope (SEM) and aqueous phases were analyzed by ICP-OES and IC for barium, iron and sulfate content. Then, three different scale inhibitors (SI) were assessed at different loadings for their efficiency to prevent scaling. Chelating agent was also used to enhance the efficiency of scale prevention and work to chelate iron ions presented in the produced water. The effect of high pH in the precipitation quantity was also studied.Results showed high potential of barium sulfate precipitation at different maxing ratios. At higher ratios of produced water, the presence of more iron deposit was observed. Analysis confirmed the barium sulfate deposition during the static jar tests. Scale inhibitors performance were found to be functions of loading and the presence of iron. Chelating agent improve the performance of SI and led to minimum precipitation potential.An optimized fracturing recipe was designed utilizing the high sulfate source water and proved to minimize the impact of sulfates scaling. The use of the chelating agent was found to be critical to enhance the scale inhibitor tolerance toward iron presence.
Impact of Rate History on Analysis of Diagenetic Fracture Injection Test DFIT and Other Impulse like Tests
Authors: Motealleh Siyavash , Jones Jack , Ghanbarzadeh Soheil 
Published: October 2019

Abstract
This work is motivated from issues that arise during the analysis of dynamic fracture injection tests (DFITs). It often occurs with DFITs that the rate history before shut in is somewhat uncertain, but the total injection volume is measured accurately. The analysis method (PTA) commonly used by the reservoir engineering community is always assumed to require an accurate and detailed rate history. In this paper two main questions are addressed: What is the impact of both poor rate measurement and imprecise knowledge of the times rates change on the shape of the resulting log-log diagnostic plot and subsequent interpretation/analysis?If the rate history is defined in any way that is consistent with total volume injected, is that sufficient to perform some useful analysis of the data?
In this study, we design a DFIT for a well and reservoir with known properties, then we use analytical and numerical simulation to produce pressure responses for the test (during injection and fall off). In the next steps, we analyze the pressure and derivative response under the conditions below: Right rate history and total volume injected.Wrong rate history, but right total volume injected.Wrong rate history and total volume injected.
The method above was repeated for a vertical well with a hydraulic fracture and a vertical well with no fracture, in order to confirm similar observation for a more standard well test when compared to a DFIT.
The results presented here imply that if the imposed rate history is incorrect with respect to rate values or times when the rate changes occur then the early time response shape is distorted in comparison to the case where the rate history is defined correctly (e.g. in a DFIT wellbore storage and linear flow before closure do not reflect the correct derivative shapes). However, if the rate history is defined in any way that reproduces the correct total volume injected, then the late time radial flow period remains unaffected and, hence, the ability to estimate reservoir properties (e.g. transmissibility and reservoir pressure) from the test is preserved. Thus, it appears that the late time part of the response is controlled by total volume injected and that total volume injected is sufficient information for estimation of reservoir properties for radial flow. This agrees with/confirms the common analysis approach used by the completions community based on the instantaneous line source solution presented by Gu, et.al. (1993)
Selecting Artificial Lift or Deliquification Measures for Deep Gas Wells in The Sultanate of Oman
Authors: Veeken Cornelis , Al Kharusi Dawood 
Published: October 2019

Abstract
Most of the gas wells operated by PDO in the Sultanate of Oman suffer from liquid loading during their production life cycle. Artificial lift or deliquification measures are key to mitigate liquid loading to maximize the capacity and ultimate recovery of these gas wells. A wide range of deliquification measures exist of which the performance depends on individual reservoir, well and surface parameters. This paper describes the use of an integrated production and economic forecasting tool that compares the technical and economic performance of different (combinations of) deliquification measures to select future deliquification scenarios.
Role of Geochemistry and Real-Time Advanced Gas Interpretation in Development Strategies of Depleted Reservoirs
Authors: El Gezeery Taher Mohamed , Halawa Youssef Ahmed , AL Shemali Nasser , Al Rashidi Mohamed , Matar Saad , Ismael Aziz , Silambuchlvan Jeevan , Al-Rashidi Tahani 
Published: October 2019

Abstract
The Minagish Oolite is one of the main reservoirs in the Minagish Field, Southwest Kuwait. The field is a large 4-way dip closure anticline structure, covering an area of about 90 square kilometers and with around 900feet of carbonates of the Minagish formation. The Middle Minagish member is the main reservoir, consisting of oolitic limestone with high permeability in the range of 10 to 1000 mD. The Lower Minagish member contains dense fine grained wackestones to packstones with low permeability. The Middle Minagish and Lower Minagish oil reservoirs contain highly undersaturated oil with API gravities of 28-34 °API and share a common FWL at 9950feet TVDSS.
The dynamic model built along with time lapsed historical (production/injection) and well surveillance (PLT, TDT, well test) data are used for tracking the movement of injected water and gas, monitoring fluid contacts and changes in saturation with time, optimizing production and planning of new wells. Nonetheless, due high density of producers existing around the field causes mutual interference amongst the neighboring wells and surprises arise while drilling new wells.
Real-time Geochemical analysis on elemental and mineral concentrations within drill cuttings/core chips, integrated with advanced mud gas data, can provide an additional analytical dataset to assess reservoir depletion and water encroachment. This advanced surface logging technology can give a better indication on water bearing zones and water encroachment when MWD/WL logs have resolution issues. When geochemical and mud gas proxies are integrated with other data sets (viz. logs, and dynamic data), they provide a better control on lithological changes and water bearing zones, throughout the entire reservoir.
Integrated geochemical and advance mud gas analysis in depleted Minagish reservoir has helped to confirm zones of interest and to determine leading edge of water aquifer. Ultimately this enabled for a unique completion design. The well MN-X, object of the study, represents a valuable case where it has been possible to identify water encroachment through geochemical proxies, aiding the completion strategy.
World's Largest Yard Testing of a Thixotropic Polymer Sealant for Chemical Annular Plug Applications in Low-temperature Horizontal Wellbores
Authors: Matar Khaled , Santin Yoann , Taku Khan , Koldig Jesper 
Published: October 2019

Abstract
Forming a retrofit annular plug on controlled acid jet (CAJ) liners in horizontal wells can be challenging. Several conformance technologies have been tested with mixed results; optimal chemical placement is problematic, and results show that conventional treatments either slump or float along horizontal sections, fail to withstand the desired differential pressure, or are not achievable at low temperatures.
This paper describes laboratory improvements and a large-scale yard test of a thixotropic polymer sealant (TPS). The TPS system is composed of an organically crosslinked polymer combined with optimized rheological modifiers, which enable predictable and controllable crosslinking times. This allows precise TPS placement into the horizontal or deviated wellbores to help control unwanted water or gas.
Extensive laboratory testing was conducted on the TPS system to formulate the optimal rheology at low temperatures. A specialized laboratory-scaled test cell was purposely built to verify the development of the thixotropic blend at low temperatures of 35 to 40°C.
After successful laboratory testing, a 520-ft long yard test was conducted to mimic a field trial. It consisted of centralized 4 1/2-in. tubing run horizontally inside a 7-in. casing. Four predrilled holes of 4-mm diameter were located midway along the tubing to represent the perforations, providing communication to the annulus of the tubing and casing. A 2.25-in. outer diameter (OD) high-pressure hose, representing coiled tubing, was placed inside the 4 1/2-in. tubing and used to deliver the TPS fluid to the perforations. The entire setup was pressure-tested to 5,000 psi and heated to 40°C using an insulated heating blanket. A high-pressure pump was used to pump and displace 6 bbl of TPS, which was sufficient to form a 300-ft annular plug. The chemical was allowed to crosslink and set for 45 hours.
Results of this yard test showed that a 300-ft TPS annular plug is capable of withstanding up to 4,620-psi differential pressure. The setup was then cut at various locations, both treated and untreated, to confirm, assess, and observe TPS placement in the cross-section of the tubulars. It was observed that the TPS can flow in the smaller spaces between the tubing and the centralizer, helping ensure optimal sealing.
The TPS system described here can be used to help reduce unwanted water or gas production in long horizontal wells with CAJ liners. The open annulus between the preperforated liner and the formation makes selective isolation for the presence of thief zones, high-permeability zones, or fractures extremely challenging. Left untreated, this can eventually result in a large increase in water production and eventually a reduction in the economic life of the field.