bluuebunny/crossref_metadata_2025 huggingface dataset:
Managed Pressure Drilling Micro Flux Technology Allows Safer Drilling in Highly Sour Reservoirs
Authors: Yang Guo Chun , Zhang Hong Jie , Epp James , Nas Steve
Published: July 2010

The developments in advanced managed pressure drilling technologies offers significantly improved safety aspects when drilling highly sour reservoirs. Drilling with a closed well bore system allows enhanced kick detection systems to be deployed on deep sour wells. Kick detection systems capable of detecting and automatically controlling a 2 bbl influx significantly increases the safety aspects of drilling highly sour reservoirs.

With these modern MPD systems it now possible to drill wells with the minimum overbalanced, which increases penetration rates in the sour reservoirs. Less drilling time and fewer trips enhance the safety aspects of sour operations. Drilling with closed systems that allow advanced and automatic kick detection systems further enhances the safety aspects of drilling sour wells. Combining these MPD systems with the vast underbalanced drilling experience gained in drilling highly sour reservoirs in Canada and North America allows small kicks to be safely handled.

This paper provides an overview of the new MPD systems and the kick detection capabilities. The paper then discusses the equipment up that can now be deployed to deal with any sour gas encountered during the drilling operations. This paper highlights the potential use of these MPD techniques for the sour gas developments in Central and Western China.
Subsurface Integration Leading to Improved History Matching: Case Study Using Malaysian Heterogeneous Carbonate Gas Field
Authors: Arsat Ahmad Hassan , Masoudi Rahim , Darman Nasir B. , Long Liew Wei , Othman Mohamad
Published: July 2010

It is well known that some of the carbonate fields in Central Luconia Gas Province, Sarawak, Malaysia, are subjected to severe geological heterogeneities and aquifer behavior. These are not usually well understood and captured during the initial field development study. This could potentially result in unreliable estimation of the hydrocarbon in place and estimated recovery factor as well as selected depletion and production strategies.

The studied field in this work, which is located in Central Luconia area, is believed to have a common strong aquifer with the neighboring fields and is a highly heterogeneous reservoir. The field has numbers of extensive and localized baffles/barriers together with high intensity of karstified areas, resulting in significant variations of reservoir characterization and hence dramatically affects the flow behavior in the reservoir, well productivity, water break-through and high abandonment pressure. Due to these heterogeneities, reliable prediction and control of the waterfront and movement, as well as the optimized production policy have significant impact to the hydrocarbon ultimate recovery from the field.

This paper presents the adopted methodology and results of the integrated study done on this complex reservoir to monitor waterfront and contact movement by incorporating the effect of the karst areas and tight zones into the field dynamic model to improve the predictability of the final history matched model. The karst areas were mapped out from the available semblance maps and the permeability of those areas were re-evaluated accordingly. The field experienced various pressure patterns and there are several pressure drifts due to the different pressure depletion pattern through the tight zones. This complex pressure patterns have been used as a guideline in incorporating the karst areas and representative tight zones in the model.

By applying this methodology, the resulting history matched model showed significant improvements and demonstrated a more representative tool in monitoring and optimizing waterfront and movement in the reservoir. Based on this study, the recovery factor of the field can also be improved by 11%.
Accurate Simulation of Non-Darcy Flow in Stimulated Fractured Shale Reservoirs
Authors: Rubin Barry
Published: July 2010

Unconventional shale gas reservoirs require stimulation via hydraulic fracturing of pre-existing fracture networks for practical exploitation, creating a stimulated reservoir volume (SRV). Within the SRV, gas flow from the nano-Darcy shale to the complex stimulated fracture network has been modeled in reservoir simulators using a variety of techniques which upscale/simplify the fracture network. The simulation techniques used in the past were normally not compared with reference solutions.

This work investigates using finely-gridded single well reference solutions (approximately 6-14 million cells) for simulating Darcy and non-Darcy flow within an explicitly modeled SRV complex fracture network, in 2-D, with and without primary hydraulic fractures, as well as scenarios which model stress sensitive permeability and later re-stimulation of a horizontal well. The network fractures use cells which are only 0.001 ft. wide.

The reference solutions are compared with standard dual permeability and MINC (multiple interacting continua) dual continua models as well as novel models which simulate flow inside of the SRV using coarse, logarithmically spaced, locally refined, dual permeability grids, and simulate flow outside of the SRV using unrefined dual permeability grids. These coarse models can be run in minutes on standard hardware, where as the reference models can take days to run on the same hardware.

We will show that excellent matches to the reference solutions are possible using a modest number of refinements to simulate the flow within the SRV when the fracture permeability and the fracture Forchheimer number (for non-Darcy flow) are scaled as described in the paper. These techniques allow the use of 2.0 ft. wide fracture conduits to mimic non-Darcy flow in 0.001 ft. wide fractures.

Good agreement between the reference and coarse models are observed even during the early flow period of the reservoir.
An Improved Laboratory Method to Estimate Flow Initiation Pressures and Near Wellbore Return Permeabilities
Authors: Suri Ajay , Sharma Mukul M.
Published: July 2010

The flow initiation pressure (FIP) is defined as the drawdown required to initiate flow when the well is put on production. The standard laboratory method used to measure FIP uses a constant flowback rate. However, as shown in this paper, this method results in a large overestimation of the FIP. Instead an improved flowback method that uses a series of constant differential pressures is shown to more accurately measure the FIP. This improved method closely mimics a constant drawdown applied in the production well. In addition, the method measures the return permeability during flowback as a function of the differential pressure (drawdown).

Two types of drilling fluids (sized calcium carbonate and bentonite) are used on sandstones and carbonates with a wide range of permeability from 4 to 1500 md. Both single-phase (only brine) and two-phase (brine and oil) experiments are conducted in lab-simulated open-hole and perforated completions to measure the FIP and the return permeability spectra.

Small values for FIP are found in all the experiments (considerably smaller than presented in the literature and measured with a constant flowback rate). The small values of FIP suggest that the pressure gradients in the field should be sufficient to initiate production in most wells.

It is shown that both the FIP and the return permeability are controlled by the internal filter cake and are not related to the removal of the external cake. However the mechanical properties of the external cake (which are related to the properties of the internal cake) can be used to estimate the FIP. The experiments suggest that for the drilling fluids used in this study a pressure drawdown of 120 psi/ft during production is needed to ensure a skin factor that is less than 1 in open-hole completions.
Development of Petrophysical Stress Models For Conversion of Core Porosity and Permeability Data from Ambient to Reservoir Conditions - A New Hybrid Approach
Authors: Williams Steve O. , Batarseh Samih S. , Solanki Max
Published: July 2010

Correction of ambient measured core data to reservoir conditions poses a major challenge in the optimal use of historical core data in reservoir description and exploitation. The use of such data in any form of reservoir evaluation without appropriate correction to reservoir conditions will result to some degree of uncertainty in reserves determination and flow performance predictions.

Core data from the Ventura Avenue field, California was used for this development. This field is structurally complex and consists of a turbidite sand sequence that is thick, shaly and thinly bedded. Porosity and permeability values are low and variable. This paper presents a new hybrid approach that uses the numerical or error minimization techniques to approximate the non-linear and double exponential relationship of porosity and permeability versus stress and takes into account the shaly and laminated sand variability, the existence of microscopic pore throat attributes and resultant stress patterns inherent in the Ventura core data. This approach eliminates the use of average parameters that are more favoured in homogenous reservoirs. It also examines and compares with other existing methodologies in the industry. The result is promising and shows a more improved and accurate porosity and permeability conversion model that can be used in both clastic homogenous and non-homogenous reservoirs.
Drillpipe Conveyed Logging Provides Solutions for Pressurized Mud Cap Drilling Operations
Authors: Toralde Julmar Shaun , Fisher Kevin M. , Collecott David J. , Stewart John C.
Published: July 2010

The variant of managed pressure drilling (MPD) used in oil and gas wells that experience severe to total circulation losses accompanied by the persistent influx of reservoir fluids is called pressurized mud cap drilling (PMCD). In this method, the well is closed in on a rotating control device (RCD) and a light annular fluid column or mud cap is maintained in the annulus. Sacrificial drilling fluid, mostly water, is pumped through the drillpipe and together with the cuttings, are swept into the loss zones. No returns reach the surface.

Once target depth is reached using the PMCD process, subsequent operations, logging in particular, need to interface with PMCD equipment and methods in order for them to take place. However, the continued presence of severe losses and the possibility of kicks make it difficult to employ conventional wireline logging methods in wells drilled using PMCD. The requirements and difficulties of logging in PMCD mode most of the time lead to the scrapping of the logging program.

This paper presents the answer to the challenge of logging safely, efficiently and successfully in PMCD mode by utilizing a commercially proven compact drillpipe-conveyed logging system known as the well shuttle, in conjunction with a downhole isolation valve (DIV) and the RCD. It provides the set-up of the proposed system and discusses its capabilities and limitations. The advantages and disadvantages of the system, as well as how it compares to wireline logging methods in PMCD operations, are also discussed.
Running Liners and Well Completion in Pressurized Mud Cap Drilling Mode in Indonesia
Authors: Toralde Julmar Shaun , Hillis Keith
Published: July 2010

Catastrophic losses accompanied by reservoir fluid influx that are commonly experienced when drilling oil and gas wells through fractured and vugular carbonates in Indonesia were solved using a managed pressure drilling (MPD) variant called pressurized mud cap drilling (PMCD) to drill through the loss zones and reach target depth (TD) with minimal non-productive time. The well is closed in on a rotating control device (RCD) and a light annular fluid column or mud cap is maintained in the annulus, while sacrificial drilling fluid, mostly water, is pumped through the drillpipe and together with the cuttings, are swept into the loss zones. The method has been largely successful in allowing adopters to reach TD, but difficulties as to how the liner and well completion can be run in PMCD mode have been encountered. The requirements of completing the well in PMCD mode most of the time leads to countless failed attempts to kill the well or circulate a mud weight that is at balance with formation pressure.

Recent PMCD operations, however, have provided success stories as to liner and well completion running, both in the onshore and offshore setting in Indonesia. These successes have largely been brought about by appropriate liner / completion system design and by the adoption of new techniques that complement the procedures involved in operating in PMCD mode. These methods have allowed for the proper management of pressures while running liner / completion with total losses and have subsequently allowed the containment of the same. The details of these methods employed for running liners and well completion safely, efficiently and successfully in PMCD mode in onshore and offshore locations in Indonesia are provided in this paper, as well its capabilities and limitations. The set-up of the liner and completion equipment that have been run in PMCD mode along with recommendations for improvement are also discussed.
Increasing Ultimate Oil Recovery by Infill Drilling and Converting Weak Production Wells to Injection Wells Using Streamline Simulation
Authors: Sayyafzadeh M. , Pourafshary P. , Rashidi F.
Published: July 2010

Developing a giant field is a challenging task; the main goal is to reach to the highest ultimate oil recovery (UOR) by finding the best locations for new producers and injectors. Besides, converting existing producers to injectors and vice versa are other ways to increase the recovery. Hence, in this approach, we use combination of infill drilling and converting producer well to injector so as to maximize UOR.

Lots of methods are recommended to develop fields, but none of them is comprehensive enough. To develop a field, the location of a new well should be considered and then its effect on the ultimate production should be investigated. This approach normally deals with testing hundreds or thousands of potential infill alternatives by numerical simulations which is a very time consuming and expensive process.

One of the newest methods to develop a field is using streamline simulation. In this approach, we suggest two main stages; first to gain the most possible advantages from the infill drilling, new producers should be drilled in sections of the reservoir where the streamline density is low and the oil saturation is high. Second, converting mostly dead producers to injectors could be a very useful method based on the density of the streamlines around the old producers. We used the method to develop a complicated reservoir. For this reason, we used grid-base and streamline simulation to verify the outcomes. The results show that UOR increases around 70 percent by infilling and switching the producers to injectors.

In this work, we use the streamline approach to develop a guideline to drill new producers and switch some of the old producer wells to injectors in order to increase the oil recovery. This method could compete favorably with EOR processes on a recovery basis for much less investment and operating cost.
Maximizing Production Life With the Use of Nanotechnology to Prevent Fines Migration
Authors: Belcher Christopher , Seth Kushal , Hollier Ron , Paternostro Barney
Published: July 2010

Sand-producing reservoirs sometimes contain particles that are small enough to pass through the regular sand control media such as proppant and screens. The tiny particles, referred to as fines, are produced into the near-wellbore region where they can cause plugging of proppant packs and perforations that can severely decline production. These formation fines can cause major erosion of screens and can plug surface equipment, and are very expensive to dispose of. As a result, many solutions have been presented in an attempt to prevent fines from being produced. These solutions range from resin applications to formation consolidation treatments, which have proven to be expensive and which most often fail to achieve their purpose. In order to approach the problem from a different perspective, nanoparticle technology was applied in conjunction with hydraulic fracturing to combat the fines migration issue.

The particular case in this paper is focused on the Gulf of Mexico; however, the technology can be applied to any reservoir in the world where formation fines affect the production life of a well. The use of nanotechnology in a hydraulic fracture allowed the operator to achieve near-initial production rate without producing fines particles. The postponement of fines entering the near-wellbore region will also protect the investments made in the downhole assembly and fracture as well as surface equipment, while extending the production life of the well and minimizing the frequency of intervention.
Successful Extended Reach Approach in Production Logging Applications
Authors: Kady Alaa , Al-Ghafly Abdulhadi A. , Al-Khalifah Hamazah A. , Green Todd , Ramsey Tim , Pascal Monis , Smith Steve
Published: July 2010

The increasing demand for horizontal production logs is driving the use of all possible well-intervention technology approaches to fulfill technical diagnostic requirements and to acquire maximum logging coverage. Maximizing coverage will result in managing and exploiting the reservoir more efficiently.

Coiled tubing (CT) is commonly used as an intervention tool for long openhole horizontal logging. As with any intervention tool, however, CT has operational limitations. Depending on the diameter of the openhole sections and the well trajectory, accessing laterals greater than 5,000 ft (1,524 m) is often problematic or not possible due to helical friction lock-up. Conventionally, we could change the geometry of the intervention (CT OD), utilize lubricants (metal/metal friction reducers) and more recently, use downhole tractors (well completion ID’s/OH OD’s might prevent some applications). The use of large–OD CT strings and lubricants have yielded 5-10% incremental reach in some cases. This paper highlights an alternative approach to enable the CT logging operation to access the entire openhole lateral.

Incorporating a downhole vibrating tool to the coiled tubing bottomhole assembly significantly extended lateral reach capabilities of recent coiled tubing logging well interventions. As a result, previously inaccessible openhole lateral sections not reached by conventional coiled tubing methods, utilizing lubricants and/or larger OD CT, have now been accessed and successfully logged.

The use of the vibrating tool as part of the logging BHA on the coiled tubing resulted in decreased friction and weight stacking, allowing the coiled tubing to run in the hole far beyond previous lock-up points.

This paper discusses two cases where production logs were completed on two onshore, openhole horizontal power water injection wells in the South Ghawar Field for Saudi Aramco Company. Each of the two wells were first attempted without the aid of a vibration tool, and as per the pre-job computer simulation total depth could not be reached due to predicted lock-up (helical buckling). The wells were then reentered with the vibrating tool, allowing the CT to reach at least 20 percent further into the openhole lateral than the previously modeled lock-up, thus allowing the unreached section to be logged.
Novel Approach in the Development of Next-generation Numerical Reservoir Simulator
Authors: Liu Wei , Li Zhiping , Han Dakuang , Jiang Hanqiao
Published: July 2010

Development of optimal depletion strategies for hydrocarbon reservoirs remains a top priority for petroleum companies in their asset management. There is a clear need for technologies that enable engineers to realize the synergy across a spectrum of reservoir management processes and subsequent establish optimal operation strategies in a fully integrated fashion. Considering the fact that a typically oil and gas production system involves multiple dynamics at different scales, effective representation and modeling of the system has been one of the greatest challenges facing the industry. In conventional approaches, furthermore, the computational intensity associated with the optimization of an integrated system (e.g. unified subsurface reservoirs, wells, and surface facilities) is either beyond current hardware capability or counteractive.

In this paper, a dynamic scaling formulation is proposed together with a nonlinear domain decomposition algorithm in order to address multiscale physics from reservoir geophysics and fluid flow at a very fundamental level. The proposed numerical scheme derives sets of dynamic scaling factors that provide a means by which the general conservations of mass, momentum and energy can be tailored and qualitatively ascertained at run time in accordance with the different physical phenomena and scales of objective domains, while the nonlinear domain decomposition technique provides an effective way to synthesize a multidomain problem into a desired global one. The methodology can be extended to simulate various systems of interest in hydrocarbon production processes, but this paper focuses only on subsurface reservoirs to accurately capture the effects of various scale fluid flow phenomena ranging from hydrocarbon components to statistical reservoir heterogeneities.
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

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

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

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

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

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

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

Production 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

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

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

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

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

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

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
Experimental Determination of Minimum Miscibility Pressure (MMP) by Gas/Oil IFT Measurements for a Gas Injection EOR Project
Authors: Saini Dayanand , Rao Dandina N.
Published: July 2010

Reliable knowledge of minimum miscibility pressure (MMP) plays a key role in the design and implementation of any miscible gas injection enhanced oil recovery (EOR) project. Various theoretical methods but few experimental methods are available for confidently determining the MMP at reservoir conditions using actual reservoir fluids.

The present experimental study reports on the determination of minimum miscibility pressure (MMP) for recombined live oil with 99.9% pure CO2 at reservoir temperature using the vanishing interfacial tension (VIT) technique. VIT technique relies on the measurements of gas/oil interfacial tension (IFT) at several pressures and reservoir temperature. MMP is then obtained by extrapolation of the measured data to zero interfacial tension. In the present study, IFT between two recombined live oil samples and CO2 was measured at reservoir temperature of 289°F and at several pressures above the bubble point pressure of 2593 psia using the pendant drop method and the capillary rise technique. The pressure was then increased in steps to approach a near zero gas/oil IFT condition. The MMP that corresponds to the pressure of zero IFT was obtained by extrapolating the measured values of gas/oil IFT to zero on IFT versus pressure plot. Such extrapolation yielded MMPs of 3533 psia and 3543 psia for the two recombined live oil samples.

This study was conducted to aid in the implementation of a proposed miscible CO2 flood in a newly discovered oil field in Mississippi by comparing the results of an independently conducted equation-of-state (EOS) modeling study based on vanishing tie-line method. Measured VIT-MMP was slightly lower (~4%) compared to the EOS-estimated dispersion-free MMP (3685 psia). This experimental study reinforces the use of VIT technique as a robust experimental method for determining the MMP and its possible use to validate the EOS models for using them in compositional simulation studies.