bluuebunny/crossref_metadata_2025_split huggingface dataset:
Removal and Mitigation of Calcium Carbonate Scale in a Sandstone Reservoir in Saudi Arabia: Long-Term Field Monitoring
Authors: Nasr-El-Din H. A. , Al-Saiari H. A. , Al-Ruwaily A. A. 
Published: December 2007

Abstract
Calcium carbonate scale was detected in several vertical wells in a sandstone reservoir in Saudi Arabia. The scale was found downhole, plugging gravel-pack screens and the intake of submersible pumps. Scale build-up caused decline in oil production from this field. The sandstone reservoir is water-sensitive and has a bottom-hole temperature of 160°F.
An emulsified-type scale inhibitor (phosphonate-type) treatment was designed to mitigate scale formation in this field. The treatment was successfully applied in more than forty-five wells. Some of these wells were de-scaled before the treatment, while others were treated before scale detection. Moreover, some of the wells were subjected to two scale mitigation treatments.
The main objective of this paper is to assess the long term outcome of the scale squeeze treatment based on field data. A second objective is to determine the actual minimum inhibitor concentration (MIC) and treatment lifetime. In addition, the impact of the second squeeze will be investigated. Samples of produced water following the scale mitigation treatment were collected and analyzed over the last five years.
The emulsified scale squeeze treatment was successfully conducted in wells with water-cut that ranges from 3–80 vol%. No operational problems were encountered during the first and second scale inhibitor squeeze treatments. The inhibitor return following the second squeeze treatment was similar to that noted following the first treatment. Lower scale inhibitor return in term of phosphorous was noted after re-squeezed treatments than that of the first squeeze. The volume of the scale inhibitor was affected the levels of the inhibitor in well flow back samples. Most of the treated wells have lifetime more than two years and the actual MIC in Field H was found to be nearly 0.9 mg/l.
Pricing of Long-Term Oil Service Contracts and Financial Risk Management
Authors: Lyadina-Saville E. 
Published: December 2007

Abstract
Pricing of long-term oil service contracts assumes projection of many components of business environment into the future. Since volatility of business, financial, and political factors have recently dramatically increased, the intelligent quantitative analysis of financial risks and their incorporation into bid/offer price curves, became of primary importance.
In this paper, we describe a commercial model for pricing long term contracts based on term-structure approach and incorporating effects of various types of financial risk, including interest rate risk, currency exchange risk, credit risk, legislation risk etc. We present a generic model of a long-time contract, and methodology of initial valuation of at-market contract, and its re-valuation during the term of agreement.
The model is applicable to a broad range of strategic marketing decisions, when effects of various types of financial risks and the duration of the contract are taken into account.
We discuss how a long-term contract may act as a tool for asset-liability management, creating a preferable risk exposure profile, and for exchange of risks between parties in a mutually beneficial manner, thus creating a ‘win-win’ business situations for both operator and service company.
An Integrated Approach to the Design and Evaluation of Hydraulic Fracture Treatments in Tight Gas and Coalbed Methane Reservoirs
Authors: Aghighi M. A. , Valencia K. J. , Chen Z. , Rahman S. S. 
Published: December 2007

Abstract
This paper presents a comprehensive approach to the design of hydraulic fracture treatments which takes into account anisotropic stress conditions, rock properties and the effect of pore pressure changes due to production in tight gas reservoirs. This has allowed us, among others, to design a re-fracture treatment. Our poroelastic model is also coupled with a production optimization scheme to optimize the design parameters for hydraulic fracture treatments.
In this paper, we present the results of a study carried out in a tight gas reservoir. Our study has shown that the fracture treatment can be successfully optimized to increase the NPV and/or ultimate gas recovery. We also demonstrated through this study that a second fracture treatment can be carried out after a period of production from the same treated interval to maintain production without drilling additional wells.
Case Study of Permeability, Vug Quantification, and Rock Typing in a Complex Carbonate
Authors: Gomaa N. , Al-Alyak A. , Ouzzane D. , Saif O. , Okuyiga M. , Allen D. , Rose D. , Ramamoorthy R. , Bize E. 
Published: December 2007

Abstract
This case study demonstrates a new method to compute continuous permeability and estimate reservoir rock type from logs in a complex, heterogeneous, Middle Eastern carbonate reservoir. The 795 ft conventionally cored interval consists of interbedded limestones and dolomites with anhydrite cement and features a wide variety of textures. In some intervals the depositional textures are preserved, in others they are highly altered by diagenesis. Vugs are developed in several intervals. Computation of permeability from porosity alone yields scatter of a factor of 700. Rock typing using only conventional logs was unsatisfactory due to the poor permeability estimation.
The effect of geological complexity on the log based prediction is overcome by including pore size distribution data from a combination of NMR and borehole electrical image logs. This data is sufficient to partition the porosity according the pore size, compute permeability and assess the rock types, independently of mineralogy, facies, and other variables. The results are validated by comparison to core derived properties and formation tester mobilities. Incorporation of the pore size information into the log based interpretation reduces the scatter in computed permeability to a factor of less than 10. The assumptions and principles of the log analysis method were validated in the lab through extensive characterization of the pore system over a range of scales. Data from a variety of methods including MICP, lab NMR, BET surface area, thin section analysis, continuous vuggy porosity analysis from the core slab, minpermeametry and other advanced research methods are included.
A key result of this study is that a relatively simple method for log derived permeability and rock type analysis in carbonates, first developed in high porosity limestones, can be successfully applied in this lower porosity (10 – 20 p.u.) carbonate. This gives us confidence to project that the method could be applicable to many other carbonates worldwide.
Well Location Selection from Multiple Realizations of a Geomodel Using Productivity Potential Maps–A Heuristic Technique
Authors: Guerra N. Y. , Narayanasamy R. 
Published: December 2007

Abstract
Heuristic technique may be called as an "intelligent guess", which reduces the search for the right answer of a usually complex problem. Such techniques are aimed to dramatically reduce the time required to solve a problem. This paper examined the Productivity Potential Map (PPM) technique as a heuristic approach tool in assisting the reservoir engineer to choose optimum well locations for field development planning. Eleven well locations were selected using PPM technique and compared with the same number of wells located using conventional STOIIP based methodology.
The exercise used information from six vertical wells in Field A, Otter Sandstone Formation (Sherwood Group). It is a discontinuous fluvial system with highly variable permeability patterns which poses a significant challenge for selecting well targets.
A comparison of simulated flow performance showed that well locations selected using PPM technique exhibied consistently better performance and minimum variance. STOIIP and PPM techniques resulted in two totally different templates for the selection of well locations. PPM technique was coherent with the expected geological trend of the area than the trend showed by the STOIIP technique.
The exercise showed that the PPM technique is a valuable method in delineating reservoir regions with favourable production potential for well placement, especially in complex sedimentary environments.
Coupled Pressure-Transient Behavior and Geomechanical Deformation in the Near-Borehole Region of Unconsolidated Clastic Rock Formations
Authors: Lee H. , Torres-Verdín C. , Sepehrnoori K. 
Published: December 2007

Abstract
We describe the development and successful testing of an axial-symmetric simulation algorithm that couples geomechanical deformation with pressure-transient analysis in a stressed vertical borehole. The objective is to quantify the sensitivity of two-phase flow properties of unconsolidated clastic sediments to presence of wellbore stress. We consider the situation in which the mechanically stressed rock formations are probed with a dual-packer formation tester to assess petrophysical properties. The simulation takes into account the mechanical deformation of the rock due to in-situ stresses as well as by wellbore stress imposed by overbalance mud circulation and by the dual-packer itself. Mechanical deformation of the compressible rock causes variations of the porosity and permeability in the near-wellbore region that are evidenced by the pressure transients measured with the dualpacker pressure probes.
The processes of multi-phase flow in the near-wellbore region due to mud-filtrate invasion and fluid pumpout are simulated with an IMPES finite-difference formulation that assumes axial-symmetric petrophysical properties and fluid distributions around the axis of a vertical borehole. On the other hand, mechanical deformation is simulated with a finite-element code that assumes 2D axial-symmetric linear deformation. The latter simulator assumes a pre-stressed initial condition due to mud overbalance and computes the incremental deformation due to fluid pumpout with the formation tester. Coupling of mechanical deformation with porosity and permeability assumes a staggered-in-time loosely coupled volumetric model that is enforced by the time-marching IMPES formulation. Sensitivity studies for the case of unconsolidated clastic formations indicate that relative variations as high as 15% in porosity and as high as 13% in permeability can ensue in the near-wellbore region due to overbalance mud pressures of 700 psi and wellbore pressures of 6500 psi applied by the inflatable packers. Such spatial variations of petrophysical properties can significantly bias the corresponding pressure-transient measurements performed with the dual-packer formation tester.
Magnetic Resonance Imaging of Methane—Carbon Dioxide Hydrate Reactions in Sandstone Pores
Authors: Graue A. , Kvamme B. , Baldwin B. A. , Stevens J. , Howard J. , Ersland G. , Husebø J. , Zornes D. R. 
Published: December 2007

Abstract
Formation and growth of methane hydrates in porous sandstone was monitored using Magnetic Resonance Imaging (MRI). A series of 3-D MRI images collected during these experiments illustrated patterns of hydrate growth. Calibrated MRI intensity changes that occured during the hydrate growth correlated with methane gas consumption and gave dynamic and quantitative in-situ information on hydrate formation rate and spatial distribution of the hydrate formed. Gas permeability was measured at various hydrate saturations and during hydrate growth. Experimentally it was verified that methane hydrate in porous sandstone spontaneously converted to CO2 hydrate when exposed to liquid CO2 at high pressure and low temperature. It has experimentally been determined that without heating, an exchange process between CO2 and methane occured allowing the injected CO2 to be stored as hydrate resulting in spontaneous production of methane, with no associated water production. The MRI images provided quantitative information on the methane production rates and amounts of methane released during the CH4-CO2 hydrate exchange reaction. Thermodynamic simulations based on Phase Field theory supported the measured results and predicted similar methane production rates observed in several reproduced experiments.
Experience from the Use of Automatic Well-Test Analysis
Authors: Oisen S. , Nordtvedt J. -E. 
Published: December 2007

Abstract
Today an increasing number of oil and gas wells are equipped with downhole and topside gauges for measurements of pressure and rates. These gauges are capable of providing data with a resolution up to every second. For each sensor, this can accumulate to millions of data points every year. Often only a small amount of these data are analyzed in order to retrieve the information they carry about well and reservoir conditions. This might be due to both time-consuming analysis and limited engineering time.
One analysis that can be performed on continuous data from permanent gauges is well test analysis after any well shut-in. In this paper, we will show that this analysis can be automated in order to minimize the engineering effort associated with performing it. This will provide the asset teams with additional information about well and reservoir conditions since today's workload for the engineers does not allow analysis of data from each well shut-in.
The analysis will be performed on real-time data for each detected arbitrary shut-in period, providing time series of the estimated parameters such as skin, permeability, reservoir pressure and drainage area. We show the benefit of linking the automated well test to an automated wavelet filter, where the filter purpose is outlier removal, denoising, compression and transient detection. This allows for developing a system whereby the data first is automatically filtered, compressed and made ready for analysis, and subsequently analyzed with a notification sent to the relevant engineers (also including a qualification on the success of the analysis). Hypothesis testing is finally performed to detect changes in data. If no changes are detected, average parameter values can be calculated. We show examples of such a completely automated well-test analyzer.
The Good, the Bad, and the Ugly of the Stage-Gate Project Management Process in the Oil and Gas Industry
Authors: Walkup G. W. , Ligon J. R. 
Published: December 2007

Abstract
Management teams across the globe have and will continue to bet on major capital projects to drive their companies' performance. Capital committed to these mega-projects has increased at a compounded average growth rate of over 12% over the last decade, and this trend is expected to continue over the next decade. To manage the shareholder value at risk in these projects, almost every major oil and gas company has invested heavily in a formal stage-gate project management process. Yet the performance of major projects has not appreciably improved, and significant project failures—both technical and economic—continue to occur.
We have investigated how the application of these state-of-the-art processes has gone astray in the oil and gas industry. We identify the key organizational and technical shortcomings that are diminishing project performance and suggest the top-ten actions management can take to gain significant competitive advantage.
Slimming the Wellbore Design Enhances Drilling Economics in Field Development
Authors: Tubbs D. , Wallace J. 
Published: December 2007

Abstract
Staying ahead of the curve sometimes requires reconsidering standard practices and vintage processes. One example that clearly illustrates this approach in the energy industry consists of planning solid expandable tubular technology into the casing design as a means to slim the wellbore. By incorporating the solid expandable tubular system at the beginning, the operator achieves a slimmer well profile while still maximizing hole size at total depth (TD), reduces drilling time to TD and reduces drilling costs.
An operator in Texas epitomizes the advantage of this approach by using the 6 x 7-5/8 in. expandable openhole liner in deep gas wells to proactively address zones prone to loss circulation. The operator maintained hole size and realized significant worth from this enabling technology. This proactive approach saved the operator over $1M per well. Applying this technology across field development projects leads to substantial savings.
For these wells, using solid expandable tubular systems to achieve a larger wellbore at TD resulted in the following features, advantages and benefits: Higher rate-of-penetration (ROP) in long intermediate casing section (36% enhancement)Overall drilling cost savings (15–20%) using slimmed wellbore vs. big bore pipe programImproved drilling performance and lower equivalent circulation density (ECD) below the solid expandable tubular system
This paper will detail how the planning and application of solid expandable tubular systems resulted in significant benefits. Drilling conditions, circumstances and environments will be discussed to illustrate how solid expandable tubular technology is conducive to efficient drilling operations. In addition, this paper will discuss the value realized from expandable applications and how these systems enhance the value of the customers' assets.
Benefits of the Novel Fiber-Laden Low-Viscosity Fluid System in Fracturing Low-Permeability Tight Gas Formations
Authors: Bulova M. , Nosova K. , Willberg D. , Lassek J. 
Published: December 2007

Abstract
Most of the low-permeability tight gas market that is treated by low-viscosity slickwater fracturing treatments results in ineffective propped fractures due to rapid proppant settling. Currently hybrid fracturing and ultra-lightweight proppants are employed for improving performance of slickwater treatments. The hybrid fracturing methodology uses a combination of linear and crosslinked gels to improve proppant placement. The disadvantages of existing lightweight proppants are their high cost and applicability only to reservoirs characterized by low closure stresses.
Novel fiber-laden low-viscosity fluid technology has been developed to improve proppant transport for hydraulic fracturing in low-temperature tight gas formations. Such a system creates a fiber-based network within the fracturing fluid that decouples proppant settling from fluid viscosity. This network entangles proppant, dramatically reduces proppant settling, and provides a mechanical means to transport and place the proppant at greater distances from the wellbore. An additional advantage of the new system lies in fiber degradability, which leads to a nondamaged fracture conductivity with time.
Fluid rheology of fiber-laden fluids was measured over a 150-230 °F temperature range under various fiber loadings. Studies showed that under bottomhole temperature and fluid pH fiber decompose and form a water-soluble species. During fiber degradation, the permeability of the fiber-laden system approaches the value of permeability for the baseline system without fiber. Compatibility study of the degradation byproducts with formation water showed no precipitate formation in high salinity environments.
The results demonstrate that the new fiber technology ensures uniform proppant placement within a long fracture, provides permeability equal to pure proppant pack values, and offers higher production rates in comparison with conventional fracturing treatments.
Accurate Volumetric-Flow-Rate- and Density-Based Water-Cut Measurement in Bubbly Liquid Hydrocarbon Flow
Authors: Volz R. , Gysling D. , Loose D. , Rawat A. 
Published: December 2007

Abstract
Oil and gas production is inherently multiphase. A significant cost of production is directed toward accurately measuring and allocating produced hydrocarbons. The presence of gas phase in liquid flow impairs accurate measurement, introducing errors in well and field production allocation. These errors distort the reservoir engineer production information and directly affect the fiscal allocation from multiple owners.
A SONAR-based system to measure the gas void fraction (GVF) next to turbine and Coriolis meters is proposed as a method to correct for gas bubbles. A test was conducted at Southwest Research Institute (SwRI) to validate this concept on realistic multiphase fluids. The SwRI test was designed to simulate separator liquid out-flow conditions and to assess the ability of GVF measurement to correct for the errors introduced by entrained gas in turbine and Coriolis meters.
The data show that both the turbine and Coriolis meters over-report the volumetric flow rate in proportion to the amount of entrained gas. Using a GVF measurement provides a simple correction to the primary measurement of both meter types to within ±1% of the reference liquid flow rate for 0–8% GVF. The Coriolis meter correctly measured the mixture (liquid + gas) density within ±1% of the reference, independent of entrained gas levels. The liquid density is required to determine water-cut and in this test it was calculated by correcting the measured mixture density for GVF. Using a simple GVF correction, the liquid density was reported to within ±1% for 0–10% GVF.
An accurate measure of liquid hydrocarbon volumetric flow rate and density independent of the amount of entrained gas can be achieved using turbine and Coriolis meters in conjunction with a SONAR-based GVF measurement. This capability enables improved reservoir management as well as increased separator design flexibility, reducing complexity, cost and weight.
The Origin and Resource Potential of Residual Oil Zones
Authors: Melzer L. Stephen , Koperna George J. , Kuuskraa Vello A. 
Published: December 2007

Abstract
Tectonics and active aquifers beneath oil-bearing reservoirs can be powerful forces in trapping large quantities of residual oil. In regions of the world where basin uplift (or subsidence) has created basinal tilt or where the oil columns are underlain by active aquifers, significant quantities of oil may have been swept from the original oil accumulation. In these situations, the once horizontal producing oil-water contact (OWC) transitions to a tilted interface across the field, creating a new and higher OWC. Below the new and now tilted OWC, there now exists a thick reservoir interval of immobile oil, called the residual oil zone (ROZ).
In the past, the ROZ was only water productive and therefore avoided. Today, with the advent of CO2 EOR and several demonstration projects, this oil zone (often quite comparable in residual oil saturation with the waterflood swept interval in the main pay zone) has been shown to be a technically viable target for additional oil recovery.
In the Permian Basin, OWC tilts have been mapped in many of the oil fields, particularly in the Permian age San Andres and Grayburg reservoirs. Examination of well logs clearly shows the presence of significant ROZs (often with 100's of feet in thickness) below the tilted producing OWC. Throughout the middle portion of the interval, the oil saturation is near residual oil saturation. The oil in place, due to ROZ thickness, is often on par with the original oil in place in the MPZ, representing a large, significant undeveloped oil resource.
This paper discusses the origin and resource potential of ROZs. The paper examines how: 1) regional or local basin tilt; 2) breached and reformed seals; and/or 3) altered hydrodynamic flow fields can form ROZs. Subsequently, the paper examines, using geologic and reservoir modeling, how key oil reservoir and aquifer properties influence the shape, size and resource potential of ROZs.