bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Hydrolysis at High Temperatures on the Apparent Viscosity of Carboxybetaine Viscoelastic Surfactant-Based Acid: Experimental and Molecular Dynamics Simulation Studies
Authors: Yu Meng , Mu Yan , Nasr-El-Din Hisham A. 
Published: September 2011

Abstract
Carboxybetaine visco-elastic surfactants have been applied in acid diversion, matrix acidizing and fracturing treatments, in which high temperatures and low pH are usually involved. Amido-carboxybetaine surfactants are subject to hydrolysis under such conditions due to the existence of a peptide bond (-CO-NH-) in their molecules, leading to alteration of the rheological properties of the acid. The objective of this paper is to study the impact of hydrolysis at high temperatures on the apparent viscosity of carboxybetaine visco-elastic surfactant-based acids, and determine the mechanism of viscosity alterations by molecular dynamics (MD) simulations.
Surfactant-acid solutions with different compositions (surfactant concentration varied from 4 to 8 wt%) were incubated at 190°F for 1 to 6 hours. Solutions were then partially spent by CaCO3 until the sample pH was 4.5, and the apparent viscosity was measured using a HT/HP viscometer. To determine the mechanism for viscosity alteration on molecular level, MD simulations were carried out on spent surfactant-acid aqueous systems using the Materials Studio 5.0 Package.
It was found that short time hydrolysis at high temperatures (for example, 1 to 2 hours at 190°F) led to a significant increase in surfactant-acid viscosity. However, after long time incubation, phase separation occurred and the acid lost its viscosity. Simulation results showed that the viscosity alteration of amido-carboxybetaine surfactant-acid by hydrolysis at high temperatures may be due to different micellar structures formed by carboxybetaine and fatty acid soap, its hydrolysis product. The optimum molar ratio of amido-carboxybetaine and fatty acid soap was found to be nearly 3:1 from our simulations.
Our results indicate that hydrolysis at high temperatures has great impact on surfactant-acid rheological properties. Short time viscosity build-up and effective gel break-down can be achieved if surfactant-acid treatments are carefully designed; otherwise, unexpected viscosity reduction and phase separation may occur, which will affect the outcome of acid treatments.
Hydraulic Fracture Optimization with a p-3D Model
Authors: Pitakbunkate T. , Yang M. , Valkó P. P. , Economides M. J. 
Published: September 2011

Abstract
In 2002 we introduced the concept of Unified Fracture Design (UFD) as a coherent way to size the fracture geometry for the expressed purpose to physically optimize the well performance. We used the Proppant Number as a correlating parameter, which in turn provided the maximum dimensionless productivity index (JD) which corresponds to the optimum dimensionless fracture conductivity, CfD. Once the latter is determined, the fracture dimensions, i.e., fracture length and width, are set.
If one assumes the fracture height is known and constant then the calculation is simple and a 2D fracture propagation model can be used. However, fracture height is not constant throughout the fracture and it cannot be considered constant during execution, depending greatly on the net pressure and vice versa.
We are presenting here an iterative procedure where the fracture height is related to the net pressure. In the procedure, for any assumed net pressure, the fracture height, along with the mass of proppant and the permeabilities of the reservoir and the proppant, lead to the Proppant Number which in turn determines the desired length and width. A fracture propagation model, such as the PKN geometry for lateral growth, coupled with a changing fracture height, leads to the calculation of the net pressure which is compared with the one assumed. Convergence of the assumed and calculated net pressure is what is sought.
The design procedure presented here is for both oil and gas wells. The design also includes the calculation of required treating pressure and finally it incorporates economics for production enhancement optimization beyond the physical optimization using UFD. Comparison of the 2D to the p-3D results points to the need and importance of the p-3D in a large array of reservoirs.
Factors Governing Distance of Nanoparticle Propagation in Porous Media
Authors: Caldelas Federico , Murphy Michael J. , Huh Chun , Bryant Steven L. 
Published: September 2011

Abstract
With a number of advantages hitherto unrecognized, nanoparticle-stabilized emulsions and foams have recently been proposed for enhanced oil recovery (EOR) applications. Long-distance transport of nanoparticles is a prerequisite for any such applications. The transport of the particles is limited by the degree to which the particles are retained by the porous medium. In this work, experiments that quantify the retention and provide insight into the mechanisms for nanoparticle retention in porous media are described. Sedimentary rock samples (Boise sandstone and Texas Cream limestone) were crushed into single grains and sieved into narrow grain size fractions. In some cases, clay (kaolinite or illite) was added to the Boise sandstone samples. These grain samples were packed into long (1 ft–9 ft) slim tubes (ID = 0.93 cm) to create unconsolidated sandpack columns.
The columns were injected with aqueous dispersions of silica-core nanoparticles (with and without surface coating) and flushed with brine. The nanoparticle effluent concentration history was measured and the nanoparticle recovery was calculated as a percentage of the injected nanoparticle dispersion. Fifty experiments were performed in this fashion, varying different experimental parameters while maintaining others constant to allow direct comparisons between experiments. The parameters analyzed in this work are: specific surface area of the porous medium, lithology, brine salinity, interstitial velocity, residence time, column length, and temperature.
Our results indicate that retention is not severe, with an 8% average of the injected amount, for all our experiments. Of the parameters analyzed, specific surface area was the most influential, with a linear effect on nanoparticle retention independently of lithology. Larger salinity increased nanoparticle retention slightly and delayed nanoparticle arrival. Velocity, residence time and sandpack length are coupled parameters and were studied jointly; they had a minor effect on retention. Temperature had a marginal effect, with two percentage points greater retention at 80°C compared to 21°C. Both surface coated and bare silica nanoparticles were successfully transported, so surface coating is not a prerequisite for transport for the particle and rock systems studied.
Integrated Workover and Re-completion Techniques to Successfully Restore Productivity for Sour Gas Field, Turkmenistan
Authors: Zou Honglan , Wang Xugang , Kang JianLi , Deng Minmin , Wang Qinghua , Zhu Huaishun , Gao Chengwu 
Published: September 2011

Abstract
This paper describes integrated workover and re-completion techniques to successfully restore productivity of Saman gas reservoir, a carbonate reservoir with H2S (vol. 3.0%) and CO2 (vol.3.6%) in Turkmenistan. Using existing old wells that have ever been producing for 5 years and already shut-in for more than 13 years is an excellent and economical way to increase production with a small investment.
Lots of complex situations in the wellbore and safety challenges, such as unmanageable wellbore corrosion, casing leak, string fishing, re-completion etc., could be encountered for existing sour wells. As a special corrosion diagnostic technology, MIT/MTT logging was used to acquire the data of metal loss, casing damage profile and cross section for joint. Workover strategies were considered and the best one was selected for complexities of old gas producers. Bottom whole assemblies (BHAs), mainly composed by SSSV system, chemical injection value and permanent packer, and were designed to corrosion control and long-term production safety. Nodal analysis and hydrate prediction were applied to optimize gas production system. Matrix acidizing by using viscoelastic self-diverting acids was carried out to remove damage for existing old wells. These key workover were conducted successfully for 17 existing well, resulting in average gas production of 30.6MMSCF from original gas production of 14.1MMSCF, and a gas productivity of 1,589 billion SCF/y. Compared with drilling new well, Workover not only economize on cost, but also speed up the building of gas field capacity.
Does Rock Really Weaken During Acid Fracturing Operations?
Authors: Joel E. O. , Pournik M. 
Published: September 2011

Abstract
Acid fracturing is a stimulation process in which the dissolution of the fracture faces creates conductivity after fracture closure. The resulting fracture conductivity depends highly on the amount and pattern of etching in addition to the strength of asperities. While there has been significant amount of studies on enhancing fluid systems to generate more optimum etching pattern, etched width, and etched length, there has been minimal work on understanding how the acid systems influence rock strength and affect closure of fracture under stress.
A systematic review of all available data on rock strength used in acid fracture modeling was conducted with emphasis on determining errors involved in each measurement. Furthermore, a detailed review of documented effect of acid on rock strength was also undertaken to understand how acid changes fracture face strength. Finally, the impact of errors in rock strength values used in conductivity correlations was studied in order to determine the importance of using correct values for rock strength.
Based on analysis of measured rock strength measurements, an average of 20% has been observed in data with greater errors for dolomite formations. Furthermore, there are great variations among rock strength values among different studies, with variations up to six times. In terms of effect of acid on rock strength, the measured weakening of rock of an average of 15% is within the measurement error limits and hence no conclusion can be made on acid weakening rock strength. Effect of errors in rock strength values used in conductivity correlations suggests significant errors in conductivity estimation, especially for softer rocks and higher closure stresses.
There have been many developments in enhancing the performance of acid fractured wells. However one major reason for the lack of success is limited understanding of the effect of acid on rock strength and incorrect estimation of rock strength. In order to understand the effect of acid fracturing on rock strength and resulting fracture conductivity under closure stress, a better method of measuring rock strength is needed in addition to detailed study on the effect of treatment parameters including acid type and contact time on rock strength variation.
Simulation Based Well Performance Modeling in Haynesville Shale Reservoir
Authors: Wang Jianwei , Liu Yang 
Published: September 2011

Abstract
Horizontal well completion and stimulation technologies are the keys to successfully develop shale gas reservoirs. The impacts of hydraulic fracture parameters, hydraulic fracture induced complex natural fracture system, and rock characteristics to well performance need to be clearly understood. Numerical simulation based methods provided a better way over other conventional methods for modeling well performance in shale gas reservoirs. However, current numerical simulation methods, dual porosity modeling and discrete modeling, have following limitations: 1) time-consuming in setting up hydraulic and natural fracture systems; 2) large computation time required.
We developed a new methodology to simplify hydraulic and natural fracture systems. Since large variations in natural fracture distribution and reservoir characteristics may result in unpredictable complex fracture network that cannot be accurately represented by discrete modeling, the hydraulic fracture and hydraulic fracture induced complex natural fracture system are treated as one enhanced zone. The simplified coarse dual porosity simulation model enables us to evaluate the effectiveness of stimulation treatment and understand shale gas production mechanism in a short time. To validate the new methodology, simulation results of a fine-grid reference model were compared with the simplified model. The simplified model greatly decreases simulation time and provides accurate results.
We applied this methodology to Haynesville shale gas wells. Historical gas production and flowing BHPs were matched. Reservoir and enhanced zone parameters were obtained after history matching, including porosity and permeability of the matrix and natural fracture system, half length, width, and permeability of the enhanced zone, as well as EUR. Simulation results indicate that if conductivities of enhanced zones are in same order shorter enhanced zone is corresponding to sharp production decline, while long enhanced zone is corresponding to relatively slower production decline. Conductivity of enhanced zone is the controlling factor for early time production performance and behaviors of flowing BHPs, while Matrix permeability and SRV half-length are the controlling factors for late timeproduction performance. Sensitivity analyses then were conducted to quantify the impact of the reservoir characteristics and enhancedzone parameters. The simulation results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.
Case Study of Unconventional Gas Well Fracturing in Hungary
Authors: Shaoul Josef R. , Spitzer Winston , Delft StrataGen , Dahan Matthew W. 
Published: September 2011

Abstract
Well Ba-E-1 was drilled in the Tompa prospect (now the Ba-IX Mining Plot) in Hungary targeting the Miocene and Cretaceous formations between 2600 and 3500 mTVD. These are tight sandstones and the expected permeabilities were in the range of 0.001 to 0.5 mD. Two hydraulic fracture treatments were performed. The first fracture treatment was in the lower part and the second treatment was in the upper part of the deepest interval. With no previous propped fracturing experience in this field, the first treatment was designed as a conventional crosslinked gel treatment to minimize the risk of a premature screenout. Following the analysis of the data from the first zone, it became clear that the average permeability was closer to the minimum expectation of 0.001 mD. Due to lower than expected stimulation effectiveness of the first fracture, and the confirmation of the low permeability, the 2nd fracture treatment was changed to a waterfrac design. This formation clearly falls into the category ‘unconventional’, and consequently was a good candidate for a waterfrac.
This paper describes the pre-frac diagnostics, fracture execution and post-frac production evaluation of this unconventional gas well. Special emphasis is placed on the use of small volume injection tests (DFIT) to obtain an estimate of the in-situ kh, since it is impossible to perform pre-fracture welltests in such a formation. The result of the DFIT analysis is then used to constrain the post-fracture welltest analysis in a numerical simulation model that includes fracture filtrate cleanup modeling. Post-frac analysis showed that the initial proppant pack damage is high and effective fracture length is much smaller than the created length, especially with crosslinked gel. The crosslinked gel treatment was not able to cleanup effectively, and therefore showed limited stimulation effectiveness. The first ever waterfrac in a gas reservoir performed in Europe showed a more significant production improvement during the short post-frac test. The results from this well suggest that, as in North America, waterfracs appear to have better initial production than crosslinked gel fracs due to better fracture cleanup in European reservoirs with micro Darcy permeability.
The Acorn Discovery: An Innovative Appraisal of an Offshore, Low Deliverability, HPHT Reservoir
Authors: Wood P. , Verlinden V. W. , Coghlan G. 
Published: September 2011

Abstract
Significant hydrocarbon volumes are present in heterogeneous, low permeability, HPHT reservoirs in the Central Graben area of the North Sea. In order to properly appraise these accumulations, an innovative appraisal strategy is required, which has to dovetail with hazard management and cost containment. In order to lower development risks these may include elements such as an extended well test and permanently installed optical distributed temperature sensor (DTS) system to monitor the flow profile.
A case history is presented of a recent appraisal well drilled on the Acorn discovery, UKCS block 29/8 in the Central North Sea. Significant STOIIP has been mapped in the continental sandstones of the Triassic-age, Skagerrak formation, where reservoir connectivity and resulting commercial productivity was the key uncertainty. A high-angle well was drilled to maximise reservoir exposure, and completed with a DTS system to monitor inflow from different layers. An extended well test was conducted and 50,000 bbls withdrawn. A data-logging device was left on the wellhead to record pressure build-up. The DTS system provided continuous flow profile information.
Well construction, completion and flow testing was successfully achieved on time and budget and was a credit to the meticulous planning and execution by the Centrica wells’ team. The required dataset was acquired for the subsurface team, much of it in real-time.
Ultimately a decision to not develop the accumulation was taken following evaluation of all data from the well. Data collected showed reservoir connectivity to be too low to support a development. Percolation theory suggests that a threshold value of N:G constrains the reservoir type encountered. The discovery appraised is interpreted to be below this threshold; however the information collected is pertinent for determining the viability of other such discoveries.
Integration of 4D Seismic Data for Water Injection Analysis of Co-mingled Wells
Authors: Ali A. , Brechet E. , Prat P. , Vert M. 
Published: September 2011

Abstract
4D seismic has been utilised on several fields for improved reservoir monitoring and management. This paper describes a specific application of 4D seismic data for the analysis of co-mingled injectors.
For optimised pressure support and sweep in water-flood projects, an injector can be completed over several different reservoir units. This, however, can introduce uncertainty on the effective injection into each zone. The reservoir quality encountered at each zone can give an indication of expected injectivity, however, this does not take into account dynamic pressure effects in the reservoir and possible completion issues. In certain cases where injection intervals are changed over time, monitoring the changes in the injectivity index during these different modes of operation can be used to infer relative injectivity potentials. PLT results, when available, can also indicate the split of injection into various zones at a given point in time. In addition, if formation pressure data is acquired after production start-up, this can be used to assess the pressure regimes in different zones. 4D seismic monitoring is the only technique to give an areal view of the reservoir, and injection anomalies from 4D seismic interpretation (3D geobody envelopes) can be used to represent the cumulative injection into a particular zone at the time of the monitor survey.
This paper contains illustrations for the comparison of injection split estimates from reservoir quality (logs), well injectivity analysis, production logging, formation pressure testing and 4D seismic monitoring. Consistency between these various data sources reduces uncertainty for important reservoir management and field development decisions (well interventions, infill planning etc.).
4D seismic has proved to be beneficial for the field development and reservoir management of many Angola Block 17 fields and this particular example demonstrates the efficacy of integration of several data sources for effective injection analysis on one such water-flood field.
Experimental Investigations of DDP and SCWD in a Naturally Fractured Reservoir, HP/HT
Authors: Gachuz-Muro Heron , Miguel-Hernandez Nemesio , Rodriguez-Roman Jesus , Luna-Rojero Erick , Aguilar-Lopez Berenice 
Published: September 2011

Abstract
The use of the Double Displacement Process (DDP) has received considerable interest as a method of Enhanced Oil Recovery (EOR). The DDP has already studied in several fields and yielded promising results. This process consists of injecting gas into waterflooded oil zones. The Second Contact Water Displacement (SCWD) Process is an extension of the DDP and consists of injecting water after a DDP. In general, fractured reservoirs have always been considered poor candidates for enhanced oil recovery; this is mainly due to the complexities involved in predicting performance in such reservoirs.
This paper investigates the efficiency of oil recovery using DDP and SCWD in a group of fractured cores. It was necessary to stack several core plugs in order to obtain accurate volumetric results. Two experiments were designed to illustrate both natural depletion and tertiary gas injection under extreme conditions; it means 5520 psi and 280.4 °F (HP/HT). Natural and nitrogen gas were used during the experiments. Results indicate that injection of natural gas in naturally fractured reservoirs with light oils could significantly recover more oil, compared to N2 injection (DDP). The study reveals that a significant amount of residual oil will be recovered by tertiary gas injection in a mature oil field where the water injection has been used during a long period. Finally, a second water displacement (SCWD) was carried out to evaluate additional recovery factors.
Real-Time Drilling Parameter Optimization System Increases ROP by Predicting/Managing Bit Wear
Authors: Gidh Yashodhan , Ibrahim Hani , Purwanto Arifin , Bits Smith 
Published: September 2011

Abstract
Tool manufacturers have made significant progress improving downhole drilling technologies, but little effort has focused on optimizing the drilling process. The set-it-and-forget-it approach and inherent inefficiencies of the automatic driller are inadequate for keeping bit parameters matched to lithology and wellbore conditions. The industry requires a new methodology to help rig-site personnel make informed drilling parameter decisions based on real-time offset data analysis that increases operating efficiency to reduce drilling costs.
To solve the problem, the service provider launched an artificial neural network (ANN) drilling parameter optimization system (DBOS OnTime) which provides rig-site personnel real-time information to ensure maximum run length from all bits and downhole tools at the highest possible penetration rates (ROP). Benefits of the new system include extended tool life, fewer trips and the ability to manage the bit's dull condition.
The objective is to replace the human factor of applying operating parameters such as weight on bit (WOB) and RPM with the intelligent ANN "learned experience." By using the ANN based software system, operating parameters can be selected based on the documented physical rock characteristics (offset log data) of the formations being penetrated and then fine tuned for the bit's specific cutting structure and wear rate. By following the real-time ANN recommendations, changes can be implemented to increase overall penetration rates (ROP) while maximizing bit life by managing the dull condition.