bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Scale Inhibitors Suitable For Deepwater Fields
Authors: Guan Hua , Farmer Paul 
Published: June 2014

Abstract
The increasing demands for oil and gas require production from increasingly deeper water depths resulting in demands for production chemicals that are suitable for deepwater and ultra-deepwater fields. The specific challenges for production chemicals in deepwater fields include bigger temperature fluctuations from seabed temperature to high-temperature/high-pressure (HTHP) environments, higher shear rates, greater pumping pressures, longer residence time and limited injection lines.
To address these issues, this paper demonstrates the whole suite of laboratory evaluation techniques that simulates the conditions experienced in the deepwater fields. These techniques include the exposure of production chemicals to a high-pressure flow loop with cyclic temperature variation from seabed temperature to 212°F (100°C), the measurement of rheology profiles at ambient and high pressure (5,000 psi), thermal stability and material compatibility. Several scale inhibitor products, including combined scale/corrosion inhibitors, have gone through the full suite of deepwater condition testing to determine their suitability for deepwater fields. Performance testing was also conducted for both pre- and post-flow loop samples. The best candidates have been designed to maintain similar inhibition performance after the flow loop with a viscosity less than 33 cP at 39.2°F (4°C) under 5,000-psi conditions; these products also have to be thermally stable and compatible with methanol/glycols and various elastomers used.
This paper provides insights into the suitable laboratory techniques and criteria for the evaluation of deepwater products. The wide range of temperature variations, high shear, long residence time and HTHP environment for the deepwater fields has been successfully simulated in the laboratory and used to evaluate deepwater scale inhibitors.
Improved Heavy-Oil Recovery by Separated-Zones Horizontal-Well Steam Stimulation
Authors: Zhong Liguo , Zhang Shoujun , Wu Fei , Lang Baoshan , Liu Heng 
Published: June 2014

Summary
Horizontal wells are widely drilled to produce heavy oil because of their large reservoir contact. For example, there are more than 500 horizontal wells operated in cyclic-steam-stimulation (CSS) or steam-assisted gravity-drainage (SAGD) processes in Liaohe oil field. The length of these horizontal wells usually ranges from 100 to 500 m. But it is challenging to recover oil along a horizontal well proportionally by conventional steam-injection processes because of poor steam conformance along the horizontal well, which is derived from reservoir heterogeneity, large horizontal-well length, and steam properties. Field investigation shows that only half of the reservoir along the horizontal well is well steamed and recovered, and that the average ratio of oil production to steam injection (OSR) is less than 0.28. In this paper, a separated-zones steam-injection process is introduced to improve steam conformance along the horizontal well; in this process, in which packers, outlets, pressure-sensitive valves, and ball sealers are involved, steam could be injected to the selected zone, separated dual zones in sequence or at one time, or separated multizones simultaneously. In order to investigate steam conformance along the horizontal well and feasibility of separated-zones steam injection, primary laboratory experiments with a sand-packaged model, numerical simulation, and field testing are carried out. These show that steam injected to separated zones could be regulated with sealed packer(s) based on the principles of steam crossflow and superimposing the effect near the packer; therefore, steam conformance along the horizontal well could be considerably improved by separated-zones steam injection. Field testing of 76 wells stimulated by separated-zones steam injection shows that up to 70% of the reservoir along the horizontal well is well steamed on average, and steam conformance is significantly improved.
CO2 Injection in Vertical and Horizontal Cores: Measurements and Numerical Simulation
Authors: Moortgat Joachim , Firoozabadi Abbas , Li Zhidong , Espósito Rogério 
Published: June 2014

Summary
In certain high-pressure and low-temperature reservoirs, the density of CO2 may be substantially higher than the oil density. Upon mixing of CO2 and oil, a gas phase with a high content of methane (C1) may also appear. When the C1 content is high, this gas phase may have a lower density than the oil. In relation to this phenomenon, we have conducted three comprehensive experiments studying CO2 injection from the top and bottom of a vertical core and injection in a horizontal core. The injection rate is 1 PV/day. This low rate allows the study of diffusion. The core diameter used in this work is 3.8 cm and the length is 27.3 cm. The tests are conducted at a pressure of 441 bar and a temperature of 60°C. At 2.6 hydrocarbon pore volume injection (PVI), the coreflood results give a recovery of 98% for bottom injection, 84% for top injection, and 92% for horizontal injection. We have also conducted an extensive set of measurements to determine swelling, viscosity, and density for the calibration of an equation of state. We simulate the experiments using a state-of-the-art higher-order finite-element three-phase compositional model. The simulations suggest that the endpoint relative permeability of the CO2-rich phase may be lower than the oil phase. The results also show that Fickian diffusion should be taken into account, but that the diffusion coefficients are reduced, because the CO2/oil mixtures are in the near-critical region for much of the injection. Even for a horizontal core there is a considerable gravity effect. One main conclusion is that there may be vast differences between CO2 injection in a 1D slim tube and in a core where there may be a 2D flow. A related conclusion is that analysis of CO2 coreflooding may provide important parameters for field-scale problems.
When Unconventional Becomes Conventional
Authors: Stefik Ron G. , Paulson Ken 
Published: June 2014

Summary
British Columbia (B.C.) has seen near-exponential growth in the areas of the Horn River and Montney unconventional shale-gas plays situated in northeastern B.C. (Fig. 1). The original-gas-in-place volume for the Montney and Horn River basins has not been formally calculated, but it has been estimated at greater than 500 Tcf and continues to be revised upwardly as new and more-refined information is obtained and development takes place. The Cordova embayment and Liard basin, east and west (respectively) of the Horn River basin, are at early stages of assessment but promise additional massive gas-in-place values.
Approximately 5 years ago, industry experts were predicting a dramatic reduction in viable gas production from the western Canada sedimentary basin, and from North America in general. Market predictions were favouring investment in import terminals for liquefied natural gas (LNG), in which gas from offshore suppliers could be imported and moved through the North American transportation grid to market. Regulators were anticipating an influx of LNG-facility applications and myriad infrastructure modifications to handle the resulting new flow regime.
In 5 short years, this dire future has been reversed completely because of the advent of economically viable methods to access gas trapped in shales and similar tight formations. At the current rates of production and exploration, there are more than 20 years of gas reserves in B.C., reversing a previous decline, as shown in Fig. 2.
B.C. is ideally positioned to provide gas to North America with ready access to a number of major gas-transportation pipelines, including systems operated by TransCanada Pipelines, Spectra Energy Gas Transmission, and the Alliance Pipeline. Many of these systems are undergoing significant capacity expansions to accommodate the influx of gas from these new plays.
This paper will explore the challenges posed to regulators in rapidly moving from conventional vertical-well developments to unconventional multiwell pads consisting of multiple fracture-stimulated horizontal wells.
Natural Gas: The Green Fuel of the Future
Authors: Taylor Robert , Tertzakian Peter , Wall Tim , Graham Mike , Young Peter J , Harbinson Sheldon 
Published: June 2014

Summary
As populations and economies continue to grow globally, energy demand will grow proportionally. Extensive work by Tertzakian (2007, 2009) has shown crude-oil supplies may not keep pace with this increased demand. The shortfall must be met by other energy sources.
Only two current energy sources have the global capacity to, by themselves, address increased energy demand in a timely manner. These are natural gas and coal.
Traditionally, the major use of crude oil has been for processing into transportation fuels, with lesser amounts being used for petrochemicals and home heating. Natural gas and coal have been used primarily for electrical generation and heating.
A pivotal transition will likely occur in which natural gas and coal begin to see increased use as transportation fuels. A battle for market share between primary fuels will likely ensue.
The objective of this paper is to present data comparing the environmental impact of using methane vs. coal. A compelling case for the use of natural gas as the future "green fuel" emerges.
Waste Management for Drillers
Authors: Gogan Ray , Vencenzo Mattia , Ayapbergenov Yerzhan 
Published: June 2014

AbstractKarachaganak Petroleum Operating B.V. (KPO) has implemented waste management process that maximizes waste reduction and waste reuse. Minimizing environmental impact was also a primary focus. This process incorporates waste minimization / segregation, oily water treatment, oil-based mud (OBM) drilled cuttings treatment and recycling of drilling muds and brines. KPO is now completing the central treatment site where it has deployed new equipment and which places it at the top of the international ladder as far as recycling, treatment and safe disposal of drilling fluids and drilling wastes are concerned. In arriving at this milestone KPO completed a 'Best Available Techniques' (BAT) review of drilling waste which is based on a review of worldwide handling and disposal techniques. This paper describes the current waste management practices established by KPO and the strategies identified by KPO for the final end point for the drilling wastes at the Karachaganak field in north-western part of the Republic of Kazakhstan.
Cuttings Re-Injection as an Environmentally Safe and Economically Efficient Drilling Waste Management Option for Karachaganak Field
Authors: Gogan R.. , Mattia V.. , Oates M.. , Gumarov S.. , Shokanov T.. , Mangiameli R.. , Simmons S.. , Boyles G.. , Woolsley G.. 
Published: June 2014

Abstract
While engineered, operated and monitored properly, Cuttings Re-Injection or Waste Injection (WI) - injection of drilling generated waste into selected subsurface formations through initiation of disposal fractures - has proven to be an environmentally friendly and cost-effective waste management technology allowing compliance with "zero discharge" requirements. Areas where it is becoming the technology of choice are continuously expanding and the FSU (Former Soviet Union) is not an exception. The first WI project in this region started in Russia (offshore Sakhalin) in 2000 and then was followed by projects in Azerbaijan (ACG) in 2006 and mainland Russia (Western Siberia) in 20081,2,3. To date, more than 4.5 MM barrels of waste have been safely injected in the region with extremely low NPT – 0.01%.
Karachaganak is a giant gas-condensate field in Kazakhstan operated by KPO. Re-injection of drilling generated waste into a selected subsurface formation has been under investigation as a potential waste management option for the field for a few years. Lithostratigraphy and geological characteristics of sub-surface formations were investigated to identify availability of suitable intervals for cuttings injection. Further, a feasibility study identified thick interbedded sandstone/claystones of the Triassic and Upper Permian, as suitable for WI purposes. Hydraulic fracture simulations showed containment of disposal fractures within the target injection intervals and indicated sufficient disposal capacity of selected formations. Once the potential disposal formations were identified, the basic surface equipment and facilities capable of safely handling expected drilling waste was designed. Additionally, as there was no actual precedence of WI technology implementation in Kazakhstan, local regulations were briefly reviewed.
Summarizing, the given paper outlines results of feasibility investigation and required surface facility and equipment parameters for WI technology implementation in the Karachaganak field.
Water Disposal Case Study in Karachaganak Field
Authors: Karibay B.. 
Published: June 2014

Abstract
One of the essential problems in the development of oil and gas fields is the proper management of the industrial wastewater handling in order to prevent environmental pollution and provide a reliable utilization of potentially environmentally hazardous waste. As a result of technological operations at the Karachaganak field, industrial water is generated at the facilities, which is utilized by injecting it between the isolated salt dome depositions. The purpose of this paper is to provide information about the industrial water handling process in the Karachaganak field, and to facilitate knowledge sharing, and promotion of experience exchange.
The following topics are considered: review of the industrial wastewater disposal system in operation at the Karachaganak field; the wastewater disposal challenges associated with hydrocarbon production and the effect of additional development of the field on the disposal requirements; ways of optimization of the disposal system; acid stimulation as a solution to the well injectivity decline; effluent analysis; monitoring and proper measurement of injection volumes and limitations of the disposal system including capacity of the disposal polygons; injection volume allocation and the inaccuracy in the measurement of the disposal volumes during simultaneous injection; the maximum allowable water injection pressure.
From the beginning of the Karachaganak field development, KPO b.v. has accumulated a vast amount of knowledge in wastewater handling that can provide a useful basis from which to optimize and enhance future wastewater related processes. It is important to understand, however, that the development of the wastewater handling is dependant on the total field development, where the risks associated with the production forecasting affect all aspects of the oil and gas field development chain.
Robust and Efficient Handling of Model Constraints with the Kernel-Based Ensemble Kalman Filter
Authors: Sarma Pallav , Chen Wen H. 
Published: June 2014

Abstract
The ensemble Kalman filter (EnKF) has recently received significant attention as a robust and efficient tool for data assimilation. Although the EnKF has many advantages such as ease of implementation and efficient uncertainty quantification, it is technically appropriate only for random fields (e.g., permeability) characterized by two-point geostatistics (multi-Gaussian random fields). Realistic systems however are much better described by multi-point geostatistics (non-Gaussian random fields), which is capable of representing key geological structures such as channels. Furthermore, the updating step in the EnKF can lead to non-physical updates of model states and other variables (such as saturations), and this problem is evident in highly nonlinear problems like compositional simulation.
In a recent paper (Sarma and Chen, 2009), we formulated a generalized EnKF using kernels (KEnKF), capable of representing non-Gaussian random fields characterized by multi-point geostatistics. In this work, we further extend the KEnKF to efficiently handle constraints on the state and other variables of the simulation model, arising from physical or other reasons. In the standard EnKF, the usual approach to handle constraints is through truncation or variable transformation, which has been shown to be problematic for highly nonlinear problems. In the KEnKF, because the Kalman update equation is solved as a minimization problem, constraints can be easily and rigorously handled via solution of a constrained nonlinear programming problem. We propose a combination of fixed point iteration and the augmented Lagrangian method to solve this problem efficiently. Note that with a kernel of order 1, the KEnKF is equivalent to the standard EnKF, and therefore, the proposed approach to handle constraints is applicable even if high order kernels are not used. The procedure is demonstrated on an example case, and is shown to better handle various state constraints compared to the standard EnKF with truncation.
Acid Diversion by Use of Viscoelastic Surfactants: The Effects of Flow Rate and Initial Permeability Contrast
Authors: Al-Ghamdi A.H.. H. , Mahmoud M.A.. A. , Wang G.. , Hill A.D.. D. , Nasr-El-Din H.A.. A. 
Published: June 2014

Summary
The purpose of matrix stimulation in carbonate reservoirs is to bypass damaged areas and increase the effective wellbore area. This can be achieved by creating highly conductive flow channels known as wormholes. A further injection of the acid will follow a wormhole path where the permeability has increased significantly, leaving substantial intervals untreated. This problem can be more significant as the contrast in permeability increases within the target zones. Diverting materials, such as viscoelastic-surfactant (VES) -based acids, play an important role in mitigating this problem.
The acid-injection rate was found to be a critical parameter to maximize the efficiency of the use of VES-based acids as a diverting chemical in addition to creating wormholes. It was found that the maximum apparent viscosity, which developed during VES-based-acids injection, occurred over a narrow window of acid-injection rates. Higher injection rates were not effective in enhancing the acidizing process, and the use of diverting material became similar in effect to that of regular acids. The use of VES-based acid was also found to be constrained by the scale of the initial permeability ratio. For initial permeability ratios greater than approximately 10, the diversion was insufficient.
The results were obtained by conducting a large set of acidizing experiments by use of 20-in.-long cores. Both single- and parallel-coreflood experiments were performed in this study. Carbonate cores were used with initial permeabilities of 4–150 md, and the flow rate was varied from 1.5 to 50 cm3/min. The initial ratio of permeability between the two cores ranged from 2 to 15. To characterize the wormholes, computerized tomography (CT) was used to generate a 3D view of the wormholes in each core.
By use of the results obtained from single cores, the acid-injection rate was found to be a critical parameter in maximizing the efficiency of the use of VES as a diverting agent during matrix-acidizing treatments. Higher injection rates were not effective in enhancing the acidizing process, and the use of diverting material produced results similar to those of regular hydrochloric acid (HCl). Parallel-coreflood experiments indicated that the use was found to be constrained by the scale of the initial permeability ratio. For initial permeability ratios greater than approximately 10, diversion was insufficient in 20-in. coreflood tests. For permeability ratios greater than 10, the acid-placement treatment needs to be designed more carefully.
Pore-Pressure and Wellbore-Stability Prediction To Increase Drilling Efficiency
Authors: Li Shuling , George Jeff , Purdy Cary 
Published: June 2014

Technology Today Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.
Abstract
Pore pressure and wellbore stability pose significant challenges to exploration drilling, particularly in regions featuring weaker rocks or subsalt formations. A lack of accurate pore-pressure prediction and wellbore-stability analysis brings many problems, such as blowouts, kicks, hole washouts, wellbore breakout, and stuck pipe. Wellbore instability also adds to drilling time and increased costs, and sometimes leads to abandoning the well before it reaches its objective. Estimates put the cost of these issues at approximately 10% of total drilling time on average. Ending wellbore-instability problems begins with the ability to predict conditions accurately and to reduce the chance of running into trouble. In this paper, commonly used methods for analyses of pore pressure, in-situ stress, and borehole shear failure are evaluated for their strengths and weaknesses. Examples are provided that demonstrate that the integration of predrill pore-pressure and geomechanics analyses with real-time monitoring consistently provides an effective way to mitigate predrill uncertainties and improve well-construction efficiency.
Constant-Pressure Gas Porosimeter
Authors: Heim A.H. 
Published: June 2014

Abstract
A method and apparatus for measuring gas porosities of rocks are described. The apparatus can be assembled from commercially available components. In principle, measurements are made by volume substitution at constant pressure. The maximum error is not more than 0.3 porosity per cent. Typical results are given.

Introduction
Determining the porosity of rock samples is one of the most important and yet most varied types of measurement in core analysis. Among the many techniques devised are the so-called "gas porosity" methods. An old and well known example is the Washburn-Bunting method. The U.S. Bureau of Mines described and later improved the apparatus for a now widely used method generally known as the "Boyle's law" method.
In the present form of the Washburn-Bunting method, the volume of air in the pores of a rock sample at atmospheric pressure is extracted and then collected in a graduated burette at atmospheric pressure. The volume of air is read directly as the pore volume of the sample. The absolute error in reading the collected volume of gas is independent of the total volume; thus, the relative error is larger when the volume is small, as it is for rocks of low porosity. In addition, the sample after measurement contains mercury, which limits its use for other analyses.
The Bureau of Mines (or Boyle's law) method measures directly the solids volume of a sample from which the pore volume and porosity are derived, using a separate measurement of the bulk volume. Gas at a few atmospheres pressure is introduced into a sample chamber of known volume containing the rock sample. The pressure is accurately measured. Following, the gas is expanded into a burette at 1 atm, and the gas volume is read directly. From the initial pressure p1 and the final pressure p2 and volume v2, the initial gas volume v1 is calculated using Boyle's law; that is, p1v1 = p2v2. Volume v1 minus the volume of the empty sample chamber is the solids volume of the sample. The accuracy of the method is limited, unless corrections are made, by deviations of the gas from the "ideal" gas-law behavior assumed in the simple form of Boyle's law.