bluuebunny/crossref_metadata_2025_split huggingface dataset:
Energized Acid Fracturing in Deep Carbonate Reservoirs. CO2 versus N2
Authors: Abel Justin Tate , Idris Muhammad , Choon Hoong Chan , Simbolon Ronny 
Published: March 2019

Abstract
Flowing back initiation for cleaning up process after a fracturing treatment in low-pressure reservoirs are becoming a challenging operation. One of the alternatives is to conduct a post-frac CT intervention using nitrogen to kickoff the flow. This operation is known to be expensive as well as time-consuming. The use of foamed fluids for fracturing operations in low-pressure gas reservoirs would help in facilitating flow- back operations and also minimizing the volume of water pumped to the formation. Nitrogen (N2) and Carbon Dioxide (CO2) are the most common gases used in foam fluids. N2 is an inert gas, and most frequently used. CO2 is more soluble in water than N2, so more CO2 is required to saturate the liquid and create the foam. But CO2 has significant advantages over N2: greater hydrostatic pressure resulting in lower treating pressure; it has more expansion during flow back that aids in total fluid recovery; the solubilized portion of carbon dioxide reduces the interfacial tension of the fracturing fluid. A study to compare the production performance from two nearby horizontal wells conducted where both were stimulated with Foam fracturing using a different gas type.
This paper describes the comparsion of acid fracturing treatment using CO2 and N2. The two wells drilled from the same pad; the horizontal parts section drilled in the opposite direction, both wells completed with OH MSF (Open Hole Multi-Stage Fracturing) completion designed for four (4) separate acid fracturing treatments in each well. The stimulation designs for both wells were prepared in such a way to have a similar fluid type, pumping sequence, and volume of reactive fluids. The major difference was the gaseous phase used to foam the fluid: CO2 was used in Well A and N2 was used in Well B. Post Fracturing flow- back parameters were measured and short pressure build-up analysis results compared between both wells.
Fracturing execution showed that CO2 can provide much higher foam quality than N2 (40% vs 12%) at the same total liquid pumping rates. Post-production showed that the well treated with CO2 gas was capable to produce at higher PI (Productivity Index) compared to the N2 well. Even after normalization to count the reservoir quality, well treated with CO2 showed better productivity compared to the N2 well.
An Integrated Approach to Deal with Challenges of Interpreting Pressure-Transient Data in Complex-Reservoir Systems
Authors: Phillips Guerrero Rodolfo J. , Al-Obathani Omar H. 
Published: March 2019

Abstract
A solid understanding of challenging reservoir complexities such as, naturally fractured "super-k" zones, layered systems, or, wellbore conditions such as, thermally induced mobility changes in the near wellbore region due to injection and uneven formation damage distribution across the wellbore, is essential for a successful development of carbonate reservoirs. These type of complexities play a major role for both reservoir fluid flow and well productivity. An efficient and holistic approach encompassing multiple data sources like image logs, production analysis logs, and pressure transient analysis (PTA) outcomes is of paramount importance in the characterization process of carbonate systems.
In this paper illustrative examples showing different complexities, at reservoir level and also at well level, are presented in a systematic way to show the importance of pressure transient analysis (PTA) insights as a building block in the description process of these challenging reservoir features. Reconciling the differences between the static and dynamic data sources in each case was a crucial step to minimize the uncertainties encountered and to significantly broaden the dynamic understanding of these complex reservoir heterogeneities under a synergistic approach. Pressure buildups and falloffs data from multi-well groups, were incorporated and analyzed by advanced numerical models. The selected interpretation models were dependent on the reservoir and wellbore condition diagnosed from the pressure derivative plots. The analyses of wireline and large, real-time Intelligent Field data have provided key dynamic well parameters, such as permeability-thickness product (kh), productivity index and anisotropy ratio (kv/kh), that were critical input parameters in the characterization process of these complex reservoir systems.
3D Reservoir-Scale Forward Geomechanical Modeling of Differential Compaction Fractures
Authors: Alzayer Yaser , Alnazghah Mahmoud , Zahm Chris 
Published: March 2019

Abstract
Differential compaction is an inherent process in carbonate systems that is thought to produce early natural fractures prior to any significant burial. Such fractures can persist and can be major permeability pathways, including areas of minor tectonic overprint. We forward model differential compaction fracturing in a carbonate reservoir in effort to predict the location of fractures in the subsurface.
3D finite-element geomechanical models are created to simulate differential compaction fracturing at a carbonate platform scale (kilometers) and the smaller carbonate build-up scale (10s of meters) commonly present within carbonate platforms. Interpreted seismic surfaces of key reservoir horizons are used as an input for the platform-scale model. Geometry of carbonate build-up from an outcrop analog is used for the build-up scale models. In both type of models layers identified to be compaction prone are restored to their expected pre-compaction state. A simplified mechanical stratigraphy scheme is adopted to distribute mechanical properties within the models consistent with their expected pre-burial properties.
Geomechanical modeling in this study was applied to a field which includes two carbonate platforms at different stratigraphic levels. Modeling results predict increased fracture intensity at the windward margin of the carbonate platform. This coincides with increased windward-leeward asymmetry of an underlying older platform. Increased fracture intensity is predicted at the center of the platform where the underlying older platform displays significantly less asymmetry. Predicted fracture locations over the platform top also correspond with the location of carbonate build-ups identified from seismic data. Fracture observations from image logs and indirectly from mud loss data within the upper platform are consistent with our modeling results. Predicted areas of greatest fracture intensity correspond with the location of wells with the highest fracture intensity observed from image logs.
Build-up scale models suggest that the build-up shape exerts a major control on the resulting differential compaction fracture pattern. Elongate build-ups tend to produce fractures oriented parallel to their axes. Circular build-ups tends to produce radial fracture patterns. Fracture orientation from image logs along with build-up shape observed using the coherence seismic attribute are consistent with these findings.
This study offers a process-based fracture modeling approach that can enhance the predictability of the location and orientations of natural fractures in carbonate reservoirs.
Underbalanced MPD of an Exploratory Well in Tight and Extra-Low Permeability Reservoir
Authors: Chen Peng , Zhou Yingcao , Wang Junjie , Chen Lei , Li Wanjun , Yang Guobin 
Published: March 2019

Abstract
Tight and extra-low permeability reservoir was usually explored by use of normal underbalanced drilling if the wellbore is stable and the formation pressure is clear. However, precise underbalanced MPD is the optimal technical solution in case the borehole is unstable and the formation pressure is unclear. Moreover, the precise underbalanced MPD would be effective for reservoir protection, enhancement of hydrocarbon discovery, improvement of ROP as well as reduction of well control risk.
No oil and gas show were found by previous conventional drilling in a tight granitic basement of Indonesia. The first exploratory well was planned to explore the broken belt of the basement to discover the oil and gas zone, increase drilling efficiency, prevent lost circulation at crushed zone of the basement and minimize drilling troubles by utilization of precise underbalanced MPD in the potential target zone. Underbalanced MPD was achieved by use of low density water-in-oil drilling fluid, and the bottomhole underbalanced pressure fluctuation was accurately and effectively controlled.
Underbalanced MPD operation was smoothly completed. Drilling with ignition under balanced managed pressure, connecting triples under balanced managed pressure, and tripping under balanced managed pressure were implemented. Slight under balanced condition of the bottomhole pressure during MPD operation was realized. The backpressure of the wellhead was accurately controlled between 55-135psi during precise MPD operation. 57 times of total accumulate successful ignition lasted 240 hours, which accounts for 80% of the total drilling time. The rate of penetration in tight target granitic formation under balanced drilling was improved and reached 10.8ft/hr. Neither losses nor overflow were detected during underbalanced MPD. Safe and high efficient drilling was realized. Good oil and gas show were observed. Abundant natural gas produced during underbalanced MPD. The basement hydrocarbon reservoir has been obtained important discovery.
Application of precise MPD technology could accomplish reservoir discovery and protection, wellbore stability and reduction of well control risk. It prevents ordinary underbalanced drilling from change over traditional overbalanced drilling due to unable to satisfy the safe drilling which would result in secondary damage to the reservoir so as to improve integrated drilling efficiency.
Application in Drilling Tool Combination Aided Design Based on Data Intelligence
Authors: Zhu Qi 
Published: March 2019

Abstract
Drilling, as a direct and effective method of opening oil and gas layers, has been widely used. A reasonable combination of drilling tools plays a key role in increasing the rate of mechanical drilling, reducing drilling costs, and reducing downhole accidents. Conventional drilling relies on years of experience of on-site workers and reference to the operation of drilling wells, making use of drilling tools and lacking scientific basis.
However, the reservoir situation is erratic, the unknown factors are very numerous, unpredictable, and the difficulty of drilling is increased. Drilling into unknown reservoirs, especially high-temperature and high-temperature risk wells, poses a huge threat to the lives of workers on site. Conventional drilling of known reservoirs will also encounter unknown problems such as drilling distance growth, stuck drilling, drilling tools falling, increased inclination, and deviation from the intended target position, which seriously reduces drilling efficiency, increases operating time, risk and drilling difficulty affected by the reasonable use of the drilling tool combination.
With the development and application of computational intelligence, through the accumulation of massive geological property data, reservoir structure data, drilling tool parameters, construction data, drilling fluid parameters and other drilling data, intelligent drilling is used to predict unknown drilling information which can reduce the risk of drilling and improve drilling efficiency.
In this paper, the work mode of "data running first, operation post" is used to further strengthen the application of drilling tools combination to improve the rate of mechanical drilling and reduce downhole problems.
Efficient CO2 Multistage Acid Stimulation in Deep Hot-Gas Reservoirs
Authors: Gromakovskii Dmitrii , Palanivel Maharaja , Lopez Alfredo , Mikaelyan Vladimir 
Published: March 2019

Abstract
Acidizing/acid fracturing is an established method of production stimulation in carbonate reservoirs. Over time, reservoirs become depleted, gas production declines, and flowback initiation can require additional time and costs. Energizing/foaming the stimulation fluid was determined to efficiently improve stimulation results and enhance post-treatment well cleanup. The gases most commonly used to energize the treatment fluids include nitrogen (N2) and carbon dioxide (CO2). This paper presents and discusses the results of an effectiveness study of foamed acidizing treatments performed using multistage completions; successful production outcomes were achieved in depleted reservoirs.
The Design-Execution-Evaluation (DEE) cycle begins with a Multistage Fracturing (MSF) well evaluation to determine whether the well is a candidate for foamed treatment. This evaluation includes studies of the reservoir data (reservoir pressure, lithology, and permeability), completion data [including fracture ports and openhole (OH) packers placement versus hole size, reservoir net pay, and lithology], and offset wells stimulation results. Foamed MSF treatments are designed to help enhance post-stimulation performance regarding cost, operational efficiency, and completion limitations. Post-job evaluation includes highlighting the treatment as well as production analysis using a numerical simulator. The post-job evaluation also serves as an input to the design of upcoming treatments.
Foamed multistage acidizing using CO2 foam proved to be successful in terms of post-treatment kickoff, cleanup, and production compared to conventionally treated wells. This success can be attributed to the following effects: Faster post-fracture cleanup as a result of the decreased liquid volume pumped into the reservoirHigher productivity resulting from acid placement benefits enabled by introducing CO2 foam (diversion, retardation)Well delivery time reduction because the post-treatment N2 lift was eliminated as a result of CO2 energy stored in the wellbore and the reservoir
This paper presents the study of CO2 MSF treatments compared to conventionally treated MSF wells. The study results can be used to further optimize treatment designs and improve field execution of upcoming MSF operations as well as help reduce overall well delivery time.
Optimizing Surveillance: A Practice for a Successful Chemical EOR Oilfield Application
Authors: Angulo Yznaga Reinaldo Jose , Quintero Luis Fernando , Arevalo Francisco J , Negm Ehab 
Published: March 2019

Abstract
This paper discusses an optimum approach to design and execution of a robust chemical enhanced oil recovery (EOR) surveillance program considering the physics and uncertainties involved during the implementation of a chemical EOR (CEOR) application at reservoir scale. The surveillance includes techniques, measuring points, and frequency of data acquisition.
Based on field experience, a robust surveillance plan plays a key role in ensuring high performance of a CEOR application during implementation and execution at reservoir conditions. A proper surveillance program should focus on acquiring information associated with the main uncertainties related to fluid-fluid and rock-fluid interactions, the impact of reservoir heterogeneities at reservoir scale, fluid dynamics, and the composition and stability of the chemical formulation. The acquired information should be given to the CEOR modeling team to follow up, interpret, and adjust the CEOR process and reservoir model. Also, the information should be given to the reservoir operation team to tune up the CEOR injection and production process to help optimize performance.
Typically, specialized literature focuses on describing CEOR formulation design and evaluation; laboratory requirements, experimental settings, and analysis results; field application design and implementation; and overall results of field applications. This work emphasizes CEOR process surveillance, its importance, and impact with respect to oilfield scale applications.
There are multiple uncertainties regarding the physical parameters and phenomena that control the performance of the CEOR at reservoir scale (e.g., are uncertainties associated with fluid saturation and properties, rock-fluid interactions, reservoir heterogeneities, and alkali-surfactant-polymer (ASP) formulation behavior at reservoir conditions). A proper surveillance design and implementation help mitigate the impact of the mentioned uncertainties.
Therefore, surveillance is paramount for the success of a CEOR application. The design and execution of a robust surveillance program should consider the main uncertainties associated with the CEOR formulation operating window, fluid-fluid and rock-fluid interactions, reservoir heterogeneities, reservoir conditions, injection-production environment, and various time scales for the timely use of the acquired information and the interpretation feedback to the CEOR modeling and operation teams.
This work discusses the physics and uncertainties considered during the design and execution of an optimized surveillance program. A systematic approach is provided considering fluid-fluid and rock-fluid interactions, reservoir heterogeneities, CEOR formulation operating window, injection – production environment, and time scales to feedback the acquired and interpreted information during the surveillance program execution.
Improving the Permeability Derivation from NMR Data for Reservoir Rocks with Complicated Pore Connectivity
Authors: Kwak Hyung , Gao Jun , Harbi Ahmad 
Published: March 2019

Abstract
The formation permeability is one of the most important Petrophysical information acquired by low field Nuclear Magnetic Resonance (NMR) data. The absolute permeability of reservoir rocks can be accurately calculated by porosity measured by NMR if permeability is well correlated with porosity [1, 2]. This is true for the rocks with all pores are well connected, such as conventional sandstone reservoir. The correlation between permeability and porosity, however, does not always established well for carbonate reservoir rocks, which are known to have heterogeneous pore-to-pore connectivity. Thus, without accurate pore connectivity information, the permeability derived from NMR data for rocks with poor connection among pores is not quite accurate.
The current study proposes a new method to measure an accurate pore-to-pore connectivity from the total volume of a fluid displacement through miscible single phase fluid mixing process. The pore connectivity factor is calculated from the fluid connectivity through different pore systems which can be derived by the volume comparison of NMR invisible D2O replacement with NMR visible H2O in each pore systems. Once the pore connectivity is measured, it is applied to the modified permeability model, such as modified free-fluid model (Timur-Coates model) [3], to calculate accurate permeability. Another benefit of the proposed method is the flexibility of D2O injection condition.
Carbonate reservoir rocks with various degrees of connectivity have been studied in the current study. For the verification purpose, the permeabilities calculated by the proposed method have been compared to those measured by other conventional laboratory techniques.
The proposed method can also be applied to NMR logging technique for accurate NMR driven permeability derivation which currently accepted as references for reservoirs with complicated connectivity, such as carbonates.
Time to Return to the Low Pumping Rates in the Fracture Stimulation of Unconventional Reservoirs
Authors: Sierra Leopoldo 
Published: March 2019

Abstract
To maximize hydrocarbon fluid recovery and economics in a challenging environment of ultralow permeability, an aggressive stimulation strategy is typically proposed. It was designed to reduce the completion or stimulation cost and time by placing multiple perforation clusters (typically three or more clusters per stage) and performing fracture stimulation by pumping the fluid/proppant system at very high rates to generate the necessary differential pressure and multiple fractures per stage.
Because the stimulation pump rate in unconventional reservoirs is typically a function of the number of perforation clusters, number of perforations per cluster, the entry hole diameter of the perforations, and a fixed required minimum rate per perforation, the resulting typical pumping rates to perform fracture stimulations to generate more than one fracture per stage is in the range of 60 to 100 bbl/min or higher. However, historically, the fracture stimulation of multiple perforation clusters performed at high pumping rates often resulted in almost 80% completion efficiency as documented by Wheaton et al. (2016). Therefore, during each stage, single or multiple perforation clusters might not be fractured or marginally stimulated, and thus do not contribute to well production.
To improve the typically observed completion efficiencies in recent years, continuing with the strategy of high treatment rates, self-soluble solid particle systems have been introduced in unconventional reservoir stimulations as an effective diversion system. The same system has been also used during refracturing operations or to increase the number of clusters per stage. This technology has been effectively deployed in the field and has provided value.
Discarding fluid and proppant logistic issues, the high treatment rate requirement for unconventional reservoir fracture stimulation demands the availability on location of high-pressure pumping equipment with very high horse power, which is available in North American operations, but not generally in most international operations. This limitation was addressed as much as possible using the available equipment or by limiting the completion strategy.
To help improve low completion efficiency in unconventional reservoirs, fracture stimulation, and the generation of at least one fracture per perforation cluster, particularly in locations where high-pressure fracturing equipment availability is limited, this paper suggests that the industry return to the conventional low pumping rate fracture stimulation treatments combined with the use of the self-degrading solid diversion systems (SDSDS) to maximize the generation of at least one fracture per perforation cluster.