bluuebunny/crossref_metadata_2025_split huggingface dataset:
Scale Prediction for Oil and Gas Production
Authors: Kan Amy T. , Tomson Mason B. 
Published: July 2010

Abstract
Scale prevention is important to ensure continuous production from existing reserves that produce brine. Wells could be abandoned prematurely due to poor management of scale and corrosion. The objective of this paper is to present an overview of scale prediction and control and the current research at Rice University to solve these problems. In this paper, the challenges of scale prediction at high temperature, pressure, and TDS are reviewed. An accurate model to predict pH, scale indices, density, and inhibitor needs at these conditions are discussed. First, the various scale types found in oil and gas production and the condition under which they form are discussed. Secondly, the relationship of pH, alkalinity, organic acids, carbonates and CO2 distribution is discussed. Thirdly, the temperature, pressure, TDS dependence of the thermodynamic equilibrium constants and activity coefficients is discussed. Lastly, the accuracy of a scale prediction program and its application is discussed. Based on a simple propagation of error estimation, the overall estimated error for calcite SI is ± 0.1. The program has been validated with literature solubility data for 6 minerals, pH data at 25 and 60 °C, and density of high TDS solutions and up to 12.7 lb/gal weighting fluid.
Enhanced Heavy Oil Recovery from Fractured Vuggy Carbonated Reservoir of Tahe Oilfield with N2/CO2 Gas Mixture
Authors: Zhao R. B. , Ke W. Q. , Wu Y. H. , Zhao H. Y. , Yue X. A. 
Published: July 2010

Abstract
Oil production in fractured vuggy carbonate reservoir has unpredicted behaviors due to complex vug connectivity, variation of oil-water interface, and oil-water multiphase flow. Early water breakthrough and rapid increased of water cut as well as decreased of productivity are often encountered in this kind of reservoir. Experiments were conducted in vug-pore artificial cores with the size of 4.5 × 4.5 × 30 cm to study the influence of viscosity and different inclination angle on the oil recovery (OR). The influence of N2 and CO2 on the relative location of the water-oil/gas-water interface were compared. These results indicate that OR increases with the decrease of oil viscosity but not always with increase of inclination angle. Under CO2 conditions, however, influence of inclination angle on OR becomes more sensitive and gravity separation becomes more important factor at higher pressures.
Stainless steel tube with inner diameter (ID) of 1 mm was used to simulate the fracture. Time for CO2 and N2 gas cap formation are different as soon as the fracture width decreases to 1mm. For N2, the time increases with increase of pressure, and takes more than 50 hours as the pressure approaches to 4 MPa. While for CO2, however, a reverse behavior is observed and the time decreases to several seconds when pressure reaches to 8 MPa.
For vug carbonated reservoir with vertical connection of pore or fracture, CO2 can efficiently change the location of oil-water interface especially at smaller connecting space and produce much more oil. The N2 gas cap can maintain the high pressure to production layer due to its lower solubility both in oil and water.
Hence, great performance can be expected in the filed performance by injection of N2/CO2 gas mixture because of gas cap formation which attributes to pressure build-up and alteration of water-oil location by N2/CO2 injection.
Water Management vs. Water Control: Profitability, Not Cost, Driving the Paradigm Change
Authors: Anthony E. P. , Mohan A. 
Published: July 2010

Abstract
At the State Oil Company of Suriname, S.A., as oil reservoirs mature, increased water production is inevitable. Decline rates &gt; 50% are common after water breakthrough. Significant reserves are bypassed when production watercuts exceeded 98% owing to limited artificial lift, transportation and /or processing capability.
Despite the limited successes in reducing the water production, in most cases, oil production is also reduced.
Similar to the concept of Cold Heavy Oil Production with Sand (CHOPS), where the strategy changed from Sand Control to Sand Production and Management, ESP technology is now used to maximize the fluid extraction rates in high watercut artificially lifted wells to achieve the required economical oil production rates. The realized Subsurface water disposal costs are much less than equivalent surface disposal costs.
In a 3-well ESP pilot[1], oil production rates increased from average 30 BOPD, 94% water on PCP to sustained 65 – 140 BOPD, 97% water on ESP (after 20 months). Additionally, in a remote field where all produced fluids were transported daily via barges to the nearest processing facility, subsurface produced water disposal reduced transportation costs by more than 25%, simultaneously creating additional storage capacity for increased oil production.
Neither ESP nor Subsurface Disposal technology is new. The paradigm change is that, at the planning stage, proactively designing completions, artificial lift equipment, processing facilities, and disposal well locations for the inevitable increase in water production, will minimize oil production decline as water production increases. The historically proven low economic success rate (&lt;30%) of water control techniques together with the excellent success rate of high-rate high-watercut wells, clearly indicates that the oil industry needs to quickly shift (not abandon) from the water control to water management mode to economically recover the millions of bypassed reserves due to high water production after water breakthrough.
Developing Offshore Tight Gas Sands and Navigating Subsurface Uncertainty
Authors: Tucker Charles F , Dean Michael C. , Pahmiyer Robert , Bate Kevin , Omotosho Peter , Walli Fared , Ahmad Zulkifli , Brittingham Pete 
Published: July 2010

Abstract

Description of Material
The Danau-Bubut gas field was discovered in 1969 with the Danau-1 (DA-1) well. This discovery came between two major gas and oil field discoveries in Brunei; South West Ampa in 1963 and Champion in 1970. In light of economic conditions and technical challenges posed by Danau-Bubut at the time, field development was deferred. Over the subsequent three and a half decades the area was intermittently explored with limited success due primarily to poor quality log data upon which to base further action. In 2007 the company returned to re-explore the area with its sixth well. The well's success in 2007 led to two further appraisal wells in 2008–09. Equipped with new technology, extensive log, core, reservoir fluid, and well test information were acquired to more accurately describe the reservoirs and their contents. This paper will discuss several findings to date in context of subsurface uncertainty in tight gas sands and briefly overview future development plans.

Application
To successfully develop tight gas sands often requires more reservoir data than conventional reservoirs (Holditch 2006). The Danau-Bubut field is no exception. The reservoirs were deposited in a lower shore-face environment and thinly bedded, very fine grained sands are interpreted as storm events. Bioturbation is abundant in most shales and present in some sands. Rich in clays, the general reservoir quality degrades with depth due to compaction. Permeability ranges from 0.01mD to 1mD in reservoirs with 8% to 12% porosity with rare occurrences of thin interbedded high permeability sands. The structure is faulted into five main blocks and several smaller blocks. The use of seismic is largely limited to structure and major fault definition. The key to improved understanding of in place volumes was extensive logging, formation pressure tests and samples, coring, and subsequent well testing.

Results, Observations, and Conclusions
The last well drilled in the appraisal campaign finished operations in early 2009 and individually drill stem tested four different zones. The uppermost zone was stimulated with a hydraulic fracture. Results from each of the four zones and treatment were surprising. Three zones were capable of producing over 10 MMscf/day each and one zone was non-commercial. Detailed results from this appraisal well will be presented and discussed. Nonetheless, significant uncertainty remains and as a result, field development will be phased to accommodate future outcomes.

Significance of Subject Matter
The Danau-Bubut field is an example of opportunity that presents a different risk profile than normal and is unlike any other field currently operated in this company's portfolio. Understanding how to bring offshore tight gas volumes to market with Danau-Bubut will enable unlocking other similar offshore potential in Brunei.
Using MARS (Multiple Application Re-injection System) Technology for Improving Oil Recovery and Reducing Production Risk
Authors: Donald Ian , Sangster Ryan 
Published: July 2010

Abstract
Using MARS (Multiple Application Re-injection System) technology for improving oil recovery and reducing production risk.
Developing the optimum subsea production system is not a straightforward process. Balancing technical, reservoir and production requirements against an economic profile, can lead to compromises at the project development stage which often leads to sub optimal production later in field life.
Subsea production is expanding into deeper waters and more hostile environments. One technology that can help alleviate the dilemma between tackling the whole range of issues at project inception and the inevitable cost pressures is called MARS (Multiple Application Re-Injection System). MARS also facilitates IOR and EOR strategies in more mature basins, brownfield developments and greenfield projects.
By adopting a strategy for production that includes MARS technology, operators can build into a greenfield development plan, the capability to retrofit production enhancing technologies such as boosting or metering when they don't have the full range of knowledge which can only be gained when production is initiated. MARS also allows new or emerging technology to be introduced when the operator is comfortable with its performance hence reducing project and initial production risk. This approach facilitates maximum flexibility with minimum outlay.
In Dec 2009, Chevron used MARS technology to enable rigless subsea scale squeeze on the Lobito Tomboco field in Angola. The technology was first deployed commercially in 2007, when BP installed two multiphase pumps on the already producing King field in the Gulf of Mexico. Other projects since then include manifold and tree mounted multiphase metering, fluid sampling, production boosting and fluid intervention on both existing production systems and new projects.
MARS is being used in the North Sea, Gulf of Mexico and West Africa.
This paper will outline the proven benefits of adopting MARS technology to increase recoverable reserves and profitability while highlighting ongoing operational experience being gained in deepwater West Africa and the North Sea.
Deepwater Developments – Challenges from an Operator point of view: The essential combination of existing field experience with innovation and new technologies
Authors: Rambaldi Eric , Mackenzie Rory 
Published: July 2010

Abstract
Deep water fields represent a significant part of our future in term of oil and gas reserves. As a major Oil and Gas Operating Company, Total has been developing deep water fields for more than 10 years. If West Africa is the major contributor with numerous large and deep projects in Nigeria, Angola or Congo, new areas are emerging worldwide. If deep water developments are real opportunities for increasing level of reserves, they also mean real technological and economical challenges: –Going deeper means subsea boosting or flow assurance major issues.–Discovering smaller reservoirs brings economical challenges.–Facing more and more complex fluids imposes new subsea alternative architectures to deal with.–Tackling longer and longer tie backs raises subsea power transmission or flow assurance complex issues.
To face those challenges, the oil and gas industry needs to explore new technological avenues such as for instance all electric systems, subsea processing with gas/liquid or liquid/liquid separation, alternative materials or subsea autonomous intervention capacities with a low cost approach in mind.
A Predictive Tool for Rapid Estimation of Components Absorption in Lean Oil Absorbers
Authors: Bahadori A. 
Published: July 2010

Abstract
Absorption is one of the unit operations which is widely used in the oil and gas gas industries. The reproduction of the operating conditions of any plant, in particular, of a natural gas processing unit is, very important because modifications and procedures of optimization can be accomplished to increase the performance and the flexibility of the process and to maintain the economic competitiveness. In the present study, a robust and simple predictive tool is developed for rapid estimation of absorption efficiency as a function of absorption factor and number of absorber stages. Predicted results are compared with the reliable data and shows excellent agreement. The average absolute deviation between the experimental data and the proposed correlation was found to be around 1 %. Results indicate that the proposed method appears to be superior owing to its accuracy and clear numerical background, wherein the relevant coefficients can be retuned quickly if new data are available in the future. The predictive tool proposed in the present work is novel and unique expression which is non-existent in the literature. This is expected to benefit the oil and gas industries in making design amendments leading to informed decisions for the prediction of absorption/stripping efficiency for a given application in oil and gas processing industries.
Predictive Tool for Estimation of Potential Precipitation From an Equilibrated Calcium Carbonate Aqueous Phase
Authors: Bahadori A. , Vuthaluru H. , Ang M. 
Published: July 2010

Abstract
CO2 sequestration in saline aquifers has been proposed as one of the most practical options for reducing CO2 emissions into the atmosphere. Massive CO2 injection into an aquifer would alter the geochemical equilibrium between the rock-forming minerals and the formation water. In this work, a novel and simple predictive tool is presented to estimate the formation of calcium carbonate scaling as a function of pH, temperature, ionic strength of the solution, calcium cation concentration, bicarbonate anion concentration and carbon dioxide mole fraction when the water mixture is saturated with a gas containing CO2, to evaluate the effect of solution conditions on the tendency and extent of the precipitation. The proposed simple method covers concentration for calcium cation concentration, or bicarbonate anion concentrations up to 10000 mg/L, temperatures up to 90°C, total ionic strength up to 3.6 and pH values ranging between 5.5 and 8. The predicted values are found to be in good agreement with the reported data with average absolute deviations being less than 2.6%. The proposed tool 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.
Calculating Equivalent Fracture Network Permeability of Multi-Layer-Complex Naturally Fractured Reservoirs
Authors: Jafari A. , Babadagli T. 
Published: July 2010

Abstract
Modeling naturally fractured reservoirs (NFRs) requires an accurate representation of fracture network permeability. Conventionally, logs, cores, seismic, and pressure transient tests are used as data base for this. Our previous attempts showed that a strong correlation exits between the fractal parameters of 2-D fracture networks and their permeability (Jafari and Babadagli, 2008, 2009a). We also showed that 1-D well (cores-logs) and 3-D reservoir data (well test) may not be sufficient in fracture network permeability (FNP) mapping and 2-D (outcrop) characteristics are needed (Jafari and Babadagli, 2009b). This paper is an extension of these studies where only 2-D (single layer, uniform fracture characteristics in z-direction) representations were used.
In this paper, we considered a more complex and realistic 3-D network system. 2-D random fractures with known fractal and statistical characteristics were distributed in the x-, and y-directions. Variation of fracture network characteristics in the z-direction was presented by a multi layer system representing three different facieses with different fracture properties. Wells were placed in different locations of the model to collect 1-D fracture density and pressure transient data. In addition, five different fractal and statistical properties of the network of each layer were measured.
The equivalent fracture network permeability (FNP) was calculated using a commercial software package as the base case. Using available 1-D, 2-D, and 3-D data, multivariable regression analyses were performed to obtain equivalent FNP correlations for many different fracture network realizations. The derived equations were validated against a new set of synthetic fracture networks and conditions at which 1-D, 2-D and 3-D are sufficient to map fracture network permeability were determined. The importance of the inclusion of each data type i.e. 1-D, 2-D and 3-D, in the correlations was discussed.
Efficiency Analysis of Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) Method for Heavy-Oil Recovery
Authors: Al Bahlani Al Muatasim , Babadagli Tayfun 
Published: July 2010

Abstract
Heavy-oil recovery from fractured carbonates is a real challenge, yet no proven technology exists as an efficient solution. Reservoir heating is generally inevitable and steam injection is the only effective way to heat heavy-matrix oil in such reservoirs using the steam distributed through fracture network. We propose a new method minimizing heat needed for efficient heavy-oil recovery from oil-wet fractured rocks by adding solvent component. Efficiency is a critical issue in this process due to potentially high cost of the process.
A new technique we proposed previously called Steam-Over-Solvent in Fractured Reservoirs (SOS-FR) consists of a cyclic injection of steam and solvent in the following manner: Phase-1: Steam injection to heat up the matrix and recover oil mainly by thermal expansion, Phase-2: Solvent injection to produce matrix oil through diffusion-imbibition-drainage processes, and Phase-3: Steam injection to retrieve the injected solvent and recover more heavy-oil. Laboratory scale static and dynamic experiments had shown that, under very unfavorable conditions (oil-wet matrix, 4,000cp crude), oil recovery at the end of Phase-3 was around 85-90% OOIP with 80-85% solvent retrieval.
In this paper, the experimental results obtained earlier were matched to a single matrix/single fracture numerical model and parameters needed for field scale simulation (matrix-fracture thermal diffusion, solvent diffusion and dispersion coefficients) were obtained. Using the data obtained through matching, field scale simulations were performed for efficiency analysis and to identify the optimal injection schemes (soaking time for cyclic and injection rate for continuous injection) and durations, and surface steam quality. Specific conclusions as to how to apply this technique efficiently in the field considering the cost of the process were reported.
Robust Well Test Interpretation by Using Nonlinear Regression with Parameter and Data Transformations
Authors: Dastan Aysegul , Horne Roland N. 
Published: July 2010

Abstract
Nonlinear regression is a well-established technique in well test interpretation. However, this widely-used technique is vulnerable to issues commonly observed in real data sets, namely sensitivity to noise, parameter uncertainty, and dependence on starting guess. In this paper, we show significant improvements in nonlinear regression by using transformations on the parameter space and the data space. In addition to providing more accurate results, faster convergence, and reduced sensitivity to starting guesses, our techniques can also provide noise reduction and data compression.
The first part of the paper discusses the basis of parameter transformations and gives suitable transform pairs for common reservoir parameters. We analyzed the homogeneous probability distribution of transformed parameters using Monte Carlo analysis and verified that the transform pairs proposed generate Cartesian parameters. We found performance improvement in terms of faster convergence and increased probability of convergence for a random starting guess.
The second part of the paper discusses nonlinear regression using the wavelet transformation of the data set. The wavelet transformation is a process that can compress and denoise data automatically. By using regression on a reduced wavelet basis rather than the original pressure data points we achieved improved performance in terms of likelihood of convergence and narrower confidence intervals. We investigated four different wavelet strategies, which differ in the method of choosing a reduced wavelet basis.
Combinations of the techniques discussed in this paper were used to analyze 20 data sets to find the technique or combination of techniques that work best with a particular data set. Using the appropriate combination of our techniques will allow for more reliable estimation of reservoir parameters using nonlinear regression.
Slim-Well Completions: A 3D Numerical Approach for Displacement to Design Effective Cementing Fluids
Authors: Pks S. , Yerubandi K. B. 
Published: July 2010

Abstract
Slim-well construction helps to significantly reduce overall well construction costs. The first step of the successful completion process is achieving effective zonal isolation. Slimhole configurations experience higher shear rates at standard annular pump rates as compared to conventional configurations. The increase in shear rate could exacerbate intermixing of the fluids, diffusion, and fingering in the annulus, thereby leading to incomplete mud and filter-cake removal and poor cement placement. Real-world consequences of these phenomena can include interzonal communication, loss of production, remedial squeeze work, and even well abandonment. Whether a conventional or slim hole well, designing an effective zonal isolation job involves balancing two technical challenges: (1) providing adequate hole cleaning through effective erodibility shear stresses; and (2) reducing channeling of mud or spacer by minimizing intermixing at fluid interfaces, controlling diffusion and minimizing fingering in the annulus. This paper deals with the underlying interactions between fluids and the challenge of controlling the aspects affecting intermixing
Intermixing lengths can commonly be as high as 500 feet for slimhole cementing jobs owing to the large difference between central and peripheral velocities of the annular fluids. In an attempt to minimize this problem, a three-dimensional (3D) numerical fluid-flow simulator was used to compare flow profiles in a low clearance 143/4-in. × 133/8-in. annulus to those in a conventional 16-in. × 133/8-in. annulus. Rheologies of the annular fluids were accurately modeled using the Herschel-Bulkley scheme. Using the same fluids and pump rates, numerical simulations in the slimhole configuration clearly showed worse displacement as compared to the standard configuration. The effects of the three rheological parameters viz., τ0, µ∞, and n of the fluids, pump rate and eccentricity on dynamic velocity profiles, displacement efficiency, intermixing lengths, and top of fluids were then studied to improve drilling-mud removal, and cement slurry placement. Results of various simulations are shared to reveal the properties and parameters that are needed to help achieve a competent cement sheath over the desired interval.