bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prospects of Foam Stimulation in Oil and Gas Wells of India
Authors: Kumar Animesh , Dutt Ankit , Singh Suraj , Sikarwar Shailesh Singh , Das Rajarshi , Kumar Kishore 
Published: July 2010

Abstract
This paper presents the scope of using "Foam Fracturing" technology in oil wells of India. Since the inception of foam stimulation technique in 1968, it has not been utilized/implemented in India despite of its various unique advantages.
"Foam Fracturing" was very successful in Arkansas. 8 wells were drilled in the Pettit Limestone formation. Initial production averaged 4.8m3/d, but after 8 weeks, the production started to decline and the wells were stimulated with a 60-65% quality foamed acid. After treatment, the production enhanced to 6.6 to 11.4 m3/d. This paper consist many other examples of success of "Foam Fracturing" technology in wells of different regions and state.
The unique advantages of foam as frac-fluid are: Exceptional flow-back and clean-up.Reduced liquid volume.Good proppant-carrying capabilities.Less operation time.
The paper also explains the basic properties of foam which makes it economically viable. There is also detailed discussion on the design of foam to suit the candidate well in the best possible way. A comparative study of different oil wells of India which were treated with the conventional frac-fluid to that where foam fracturing was used in different countries was done. The conditions of these wells are very much similar to the wells here in India.
The new fields in India like Krishna-Godavari (KG) basin and Cauvery basin are also suitable for "Foam Fracturing" technology.
Thus, through the endeavor, we want to conclude that the technology of "Foam Stimulation" can prove fruitful in India as well and hence must be implemented at the earliest.
N.B.: The laboratory and numerical simulation work for modeling foam as frac-fluid for Indian oil-wells are in progress.
Well Test Interpretation Model on Power-law Non-linear Percolation Pattern in Low-permeability Reservoirs
Authors: Shun LIU , Feng-rui HAN , Kai ZHANG , Ze-wei TANG 
Published: July 2010

Abstract
This paper presents a new percolation method that is power-law non-linear percolation pattern in low-permeability reservoirs. Well test interpretation model on power-law non-linear percolation pattern is given and the way how to solve those equations is provided. To analyze and compare well test interpretation models of four different percolation pattern. The balance factor of power-law percolation pattern responds little to pressure and the power-law index responds greatly to pressure yet. Models were used to oil field can those results to be achieved that, new established model presents type curves are more gently and less than that obtains from the method of start-up pressure gradient. Also, this non-linear effect measure makes derivative of pressure curve less and more early time than that gets from the closed boundary effect and there are be obviously distinction. This study addresses type curves capable of analyzing field cases and offers more logical and reliable results.
Stimulation of Carbonate Reservoirs Using GLDA (Chelating Agent) Solutions
Authors: Mahmoud M. A. , Nasr-El-Din H. A. , De Wolf C. A. , LePage J. N. 
Published: July 2010

Abstract
The objective of matrix acidizing process is to create channels through the damaged zone in the near wellbore. Creating channels through the damaged zone yields a negative skin and improves the recovery in oil and gas reservoirs. The use of conventional matrix acidizing treatments with HCl is not effective in some cases due to corrosion and rapid acid spending at high temperatures. Previous studies have demonstrated the use of ethylenediaminetetraacetic acid (EDTA), hydroxy ethylethylenediaminetetraacetic acid (HEDTA), and DTPA (diethylenetriaminepentaacetic acid) as alternatives for HCl to stimulate carbonate reservoirs. These chelating agents were tested only on short cores (less than 5 in. length).
GLDA (L-glutamic acid-N, N-diacetic acid) chelating agent was introduced that can be used as an effective stimulation fluid for carbonate reservoirs. Unlike HCl, GLDA can be used at very low injection rates and can create wormholes without face dissolution problems or washout. Calcium carbonate cores 1.5 in. diameter of 6 and 20 in. lengths were used in this study. The optimum conditions for the formation of wormholes were studied using core flood experiments. These conditions were: flow rate, temperature, concentration and pH. Other factors such as rock permeability and core length were also examined.
GLDA was found to be very effective in creating wormholes at low injection rates and low to moderate pH values. Increasing temperature increased the reaction rate and more calcium was dissolved and larger wormholes were formed. Also, the optimum injection rate and GLDA concentration that should be used to minimize the volume of the fluid in the stimulation treatment were determined.
Unmanned Offshore Platforms: Automation Kit
Authors: Pinosofa A. , Ramirez A. J. , Cortazar Cruz O. S. , Ravelo Y. , Yermagaliyeva G. 
Published: July 2010

Abstract
In the extreme volatile oil & gas market, all the operators are focusing on cost reduction to maximize the profits. Site personnel represent one of the top OPEX contributors to the offshore operation, either in term of direct as well as indirect costs. Each position in the offshore site implies an average of 2.5 people to assure the plant operation. Those prople are organized in multiple shifts to cover the full site time requirement. As direct cost, this means an average of € 500k/year per each skilled position. Each position implies also a set of indirect costs related to the logistics such as: mobilization, board & lodging and related service, sometimes very expensive.
Decrease or limit the man effort at site would bring a great impact to the operation effectiveness. Turbocompressor units usually represent the core equipment in the platform.
Could it reduce the site men effort to monitor, control & diagnosis the equipment remotely onshore? Could it improve the reliability and availability to minimize the daily maintenance? Is that really something brings value to operators? Should the OEM focus automation packages to retrofit exiting units or change design approach of the next generation of equipment?
Proper market analysis in this paper as well as real voice of the operators and experience can answer to those questions. And also in this paper will demonstrate a biz case the value the hypotetical automation kit could bring to the operators.
An Industry Perspective of Using Towed Passive Acoustic Monitoring (PAM) for the Detection of Marine Mammals at Sea During Seismic Surveys.
Authors: Hedgeland David , Pierpoint Chris , Wyatt Roy , Rypdal Cato , Gubin Dennis 
Published: July 2010

Abstract
Visual monitoring has been the primary method of detecting marine mammals during offshore operations for many years. The effectiveness of visual detection is reduced however, when animals are not at the surface and during periods of poor visibility.
Towed passive acoustic monitoring (PAM) offers an opportunity to detect and indicate the location of marine mammal vocalisations relative to a hydrophone streamer being towed from a moving vessel. Vocalising marine mammal species may be identified by the characteristics of their calls and sonar clicks. Though basic automatic detection and species recognition functionality may be available, experienced and specialised operators are required to maximise detection/identification efficiency and minimise the likelihood of false detections.
PAM is becoming an increasingly important monitoring tool during marine mammal population studies. When used as a monitoring tool in conjunction with mitigation measures, PAM provides the potential to reduce the risk of impacts from human activities on marine mammals. Though considered particularly useful for monitoring during periods of poor visibility, current towed PAM technology requires further development and field testing in order to provide a consistent and reliable real-time monitoring tool at sea.
There is increased regulatory interest in using PAM as a means of monitoring marine mammals at sea during seismic survey operations at night or during periods of low visibility. As with any new technology, there is a need to ensure that both capabilities and limitations of the method during real-time Industry conditions are understood before requiring its use as a monitoring tool.
Lessons learned from industry experience using PAM systems in the field will increase the understanding of current capabilities and limitations and will lead to further improvement of the technology.
Recent experience of deploying towed PAM systems and testing a new; standardised user interface under real-time industry conditions, has identified some practical challenges of using PAM as a mitigation monitoring tool during offshore operations.
Optimal Field Development Through Infill Drilling for the Main Pay in South Rumaila Oil Field
Authors: Al-Mudhafer W. J. , Al-Jawad M. S. , Al-Shamma D. A. 
Published: July 2010

Abstract
Study of determining the optimal future field development has been done in a sector of South Rumaila oil field/ main pay. The aspects of net present value (economic evaluation) as objective function have been adopted in the present study.
Many different future prediction cases have been studied to determine the optimal production future scenario. The first future scenario was without water injection and the second and third with 7500 surface bbls/day and 15000 surface bbls/day water injection per well, respectively. At the beginning, the runs have been made to 2028 years, the results showed that the optimal future scenario is continuing without water injection because the cumulative oil production and net present value for this case is higher than from the two another cases, but According to the relationship between net present value and future production time, the abandonment time was estimated before end of December 2014 for all above cases. So, the optimal future scenario was with water injection of 15000 surface bbls/day if the surface injection facilities can handle this rate.
For achieving the reliable forecasts for these prediction scenarios, a comparison has been made with other modern studies which adopted on the same field.
Estimation of Salinity of Salty Crude Oil Using Arrhenius-type Asymptotic Exponential Function and Vandermonde Matrix
Authors: Bahadori A. , Vuthaluru H. , Ang M. 
Published: July 2010

AbstractProduction of wet crude due to increase in oil-water contact in many oil fields has been a growing field problem and it has affected the quality of crudes. In almost all cases, the salt is found dissolved in the water that is dispersed in the crude oil and its separation is not an easy task because desalting is considered a critical operation due to the importance of meeting the specifications of the acceptable quantities of salt and water in the treated oil. For these reasons, measurements of salt and water content in crude oils are very important in all oil industry operations including crude oil production, processing, transportation and refining. In this paper, an attempt has been made to formulate a simple-to-use method which is easier than existing approaches, less complicated and with fewer computations for accurate and rapid estimation of crude oil salinity as a function of brine quantity that remains in the oil, its salinity (in vol% of sodium chloride concentration) and temperature using an Arrhenius-type asymptotic exponential function and Vandermonde matrix. The proposed method predicts the Salinity of Salty Crude Oil for temperatures up to 373 K and sodium chloride concentrations up to 250,000 ppm (25% by volume). Estimations from the proposed correlation are found to be in excellent agreement with the reported data in the literature with average absolute deviation being 0.3%. The proposed method is superior owing to its accuracy and clear numerical background based on Vandermonde matrix, wherein the relevant coefficients can be retuned quickly for various cases. The tool developed in this study can be of immense practical value for the engineers to have a quick check on the salt content in the crude oil at various conditions without opting for any experimental measurements. In particular, petroleum and field engineers would find the approach to be user-friendly with transparent calculations involving no complex expressions.
Sand-by-Sand Screening Methodology in Offshore Mature Fields: A Case Study
Authors: Blanco L. , Paranjpe V. , Grimaldi J. , Segnini C. , Johnson G. 
Published: July 2010

Abstract
After REPSOL took over the operation of the TSP asset (Teak, Samaan, Poui gas/oil fields) at the end of 2005, it was considered important to have an indigenous evaluation of the reserves/production potential of these fields. This need was further underscored when the results were obtained from the rig operations carried out in 2007. It was then decided that such an evaluation would be the key to defining and prioritizing future work programmes. As such, the main challenges towards carrying out a detailed technical evaluation were: Business Challenges:▪Field decline was ongoing and new opportunities were required for the near future▪An answer to the potential of the field was necessary in a short period of time (one year) in order to design the Company's strategyTechnical Challenges:▪Very mature offshore fields with more than 35 years of production, hence a good deal of information to be collected, analyzed and interpreted in a short period of time. The data was scattered and required a detailed QC process▪Complex nature of the reservoirs with 16 reservoir sand units (vertically stacked), highly compartmentalized with complex tectonic geometries and facies distribution▪No previous reliable reservoir evaluations were available
To carry out a detailed technical analysis – i.e. generation of maps/models etc. – for all the reservoirs, the effort would have been immense and would have delayed the decision making by a few years. The screening study was conceptualized with the objective of identifying the reservoirs with maximum potential and to direct further technical effort on those reservoirs so that early monetization of the reserves is possible. As a result of this study, key reservoir opportunities were identified and prioritized, having possible potential for incremental reserves through workovers, infill and step-out drilling. Further efforts would be focused on a detailed technical evaluation of the selected reservoirs.
Importance of Using Pressure Data While History Matching a Waterflooding Process
Authors: Barroeta R. G. , Thompson L. G. 
Published: July 2010

Abstract
In order to demonstrate the importance of using observed pressure data for history matching an early-stage waterflooding process, a novel workflow for experimental design, assisted history matching and probabilistic analysis, was applied to analyze laboratory displacement test measurements. In order to achieve matches between experimental and model data, an evolutionary global optimization technique was used and three different strategies were investigated: matching pressure data only, matching production data only and matching both pressure and production data. For the purpose of generating model displacement data, a one dimensional, two-phase simulator was run.
Tornado plots on the matched data reflect that calculated model pressure values appear to be more sensitive to changes in the dynamic calibration parameters (uncertainty parameters) than calculated cumulative fluid values. This implies that use of the pressure drop information enhances the ease with which acceptable history matches can be obtained. Additionally, the results obtained while history matching pressure only were better than those from matching volumetric data only. The results were validated by crosschecking the probabilistic forecasting with real postmortem observed values and by comparing calibrated uncertainty parameters with core petrophysical properties (laboratory analysis).
Identifying Injector-Producer Relationships in Waterflood Using Hybrid Constrained Nonlinear Optimization
Authors: Lee H. , Yao K. , Okpani O. O. , Nakano A. , Ershaghi I. 
Published: July 2010

Abstract
A key barrier to optimal field management, i.e., maximizing oil production and reducing operational cost, is the understanding of underlying structure of the field, which continuously changes over time. Analyzing readily available injection and production data to identify injector-producer relationships (IPRs) offers a convenient way to this understanding. The capacitance-resistive model (CRM) provides an intuitive and straightforward way to characterize IPRs through production and injection rate fluctuations. However, it requires a large number of model parameters. The number of parameters increases quadratically with number of production and injection wells in the reservoir. For fields consisting of hundreds of wells identifying IPRs among the wells is challenging. Moreover, there is no analytical solution for solving the parameter values due to the nonlinear time constant parameters of the CRM and the constraints. This paper presents a new method, a hybrid constrained nonlinear optimization (HCNO), for estimating the optimal parameter values of a nonlinear predictive model. HCNO is optimization-based algorithm such that it estimates the optimal values of the model parameters satisfying the constraints. HCNO separates the connectivity and time constant parameters of CRM then uses two different optimization algorithms. A constrained nonlinear optimization algorithm is applied to estimating the time constant parameters, and subsequently the connectivity parameters are estimated by a constrained linear optimization algorithm with the estimated time constant parameters. The coupled optimization is performed at each iteration, which leads to faster convergence. HCNO is tested on several synthetic oil fields. The result showed that the search time and the prediction error by HCNO were significantly less than those of estimating the parameters as a whole by solely constrained nonlinear optimization. The identification of IPRs by the optimal parameter estimation will help field engineers’ decision making process in optimizing waterflooding.
Energy Conservation and Oil Production Opportunities in the Oil Field
Authors: Al-Shuwaikhat Hisham I. , Al-Buali Muhammad H. , Al-Shehri Ayedh M. , Al-Eid Mufeed H. , Al-BenSaad Zakareya R. , Al-Marri Hamad M. 
Published: July 2010

Abstract
Energy conservation is a key aspect to reduce high power consumption in a Gas Oil Separation Plant (GOSP) where oil is separated from water and gas, then shipped. Saudi Aramco is putting a lot of effort into producing large fields, such as the oil field at optimized energy consumption; especially in the summer time, which is always a high demand peak period for power.
A swing line network has been constructed between major field plants to provide flexibility for meeting required production targets by reallocating oil production and reduce energy consumption. The swing lines were designed and constructed in late 2005. Presently, they are in use and emerged as a proven tool to lower operating expenditure (OPEX) for plants. This has not only reduced the cost of power but also minimized the environmental impact to some extent by reducing CO2 emissions.
Also, as part of the field production strategy, several oil producers with high water cut were shut-in adding a very remarkable power consumption reduction at their respective plants. This reduction in water production was reached by shutting some of the disposal pumps and/or deferral of forecasted upgrading of the disposal systems. It's worth mentioning that the shut-in of such marginal producers is not solely meant to reduce energy consumption, it's a part of the reservoir production strategy.
This paper will focus on energy conservation opportunities that have been realized by utilizing swing lines and controlled water production strategy in part of the oil field.
The Effect of Salinity of Injection Brine on Water Alternating Gas Performance in Tertiary Miscible Carbon Dioxide Flooding: Experimental Study
Authors: Jiang Haifeng , Nuryaningsih Lily , Adidharma Hertanto 
Published: July 2010

Abstract
The effect of salinity of the injection brine on Water Alternating Gas (WAG) performance in tertiary miscible carbon dioxide (CO2) flooding is investigated. Coreflood experiments are performed in Berea sandstone core, from which the WAG performance, such as percent oil recovery, tertiary recovery factor, and CO2/Gas utilization factor are determined. The core flooding experiments are conducted at 60 °C and at miscible condition, i.e., 20% above the minimum miscible pressure (MMP) of the oil sample. A model oil, which is a mixture of 50 wt% n-decane and 50 wt% n-hexadecane, and a crude oil from Cottonwood Creek are used. For experiments with model oil, artificial injection brines are made by dissolving NaCl into distilled water with different salinities ranging from 1000 to 32000 ppm (mg/L); artificial brines containing 4000 ppm NaCl and 4000 ppm CaCl2 are also used to investigate the effect of divalent salt in the injection brine on WAG performance. For experiments with Cottonwood Creek oil, artificial brines containing 20000 ppm NaCl and 10000 ppm CaCl2 are used as the connate brines and artificial brines containing 66.67 wt% of NaCl and 33.33 wt% of CaCl2 with salinities ranging from 10000 to 32000 ppm are used as the injection brines. Six alternate cycles of brine and CO2 with a half-cycle slug size of 0.25 pore volumes (PV) and a CO2/water ratio (volume ratio) of 1:1 are injected in every core flood test. Comparisons of WAG and continuous gas injection (CGI) are also made on both model and crude oils. At the same miscible condition, the tertiary recovery factor of WAG is demonstrated to be higher than that of continuous CO2 flooding. The tertiary oil recovery and recovery factor of both model and crude oils are found to increase slightly with the salinity of the injection brine due to the decrease in the CO2 solubility in brines. The CaCl2 in the injection brine is found to have similar effect as NaCl. The increased oil recovery of WAG over water flooding can be higher than 50% of Original Oil in Place (OOIP) for model oil and 35% of OOIP for crude oil.
Review of Cuttings Transport in Directional Well Drilling: Systematic Approach
Authors: Nazari T. , Hareland G. , Azar J. J. 
Published: July 2010

Abstract
Hole cleaning during directional well drilling is a major concern in the oil patch and must be monitored and properly controlled during the entire drilling operation. Inadequate drilled cuttings removal can cause many costly problems such as mechanical pipe sticking, excessive torque and drag, difficulties in casing/cementing and in logging. Low fluid annular velocity, lack of drill pipe rotation and the wrong mud properties are primary factors in the inadequacy of effective hole cleaning.
This paper presents a thorough review on previous hole cleaning studies and discusses an approach that uses physical-systematic methodology that is more suited for monitoring and controlling hole cleaning problems. The approach is based on relating output and internal state vectors to input vectors. The concept basis is to classify the drilling parameters into inputs, internal states and outputs, check the observability (condition monitoring) and controllability of the hole cleaning as an internal state during drilling.
Previous studies on drilled cutting transport can be grouped in four categories: Sensitivity analysis –internal states changes vs. input changesModeling – physical relations of inputs and internal stateMonitoring – using real time measured data to estimate the internal stateControl – change inputs until achieving the desired internal state