bluuebunny/crossref_metadata_2025 huggingface dataset:
Developing a Process Safety Management Plan for Production Facilities and Gas Plants
Authors: Arnold K. E. , Thro M. E.
Published: June 2014

The paper describes a Process Safety Management (PSM) Plan to satisfy the requirements of OSHA 1910.119 for onshore production facilities and proposed MMS requirements for offshore operations. The information presented will help operators better understand the requirements as they apply to producing facilities and gas plants, and develop a plan to meet these requirements.
Experimental Investigation of Cresting and Critical Flow Rate of Horizontal Wells
Authors: Aulie Tove , Grødal Evert , Asheim Harald , Oudeman Piet
Published: June 2014

Cresting towards horizontal wells with bottom water drive and edge water drive has been experimentally investigated using a laboratory model. For bottom water drive the experimental results are compared with two models for transient crestal behavior. The range of applicability for critical rate estimates by the analytic model is found.

For edge water drive the model developed predicts the measured steady-state supercritical production performance over a wide range of flow rates. As a consequence of the model and experimental results follows that by increasing the total production, net oil rates much above the critical may be obtained.
The Approach to Passive Fire Protection Design for the North Everest and Lomond Platforms
Authors: Krisa T. E. , Cottingham O. F. , Medonos Sava , Prager Jacob , Yasseri S. F.
Published: June 2014

Traditional methods of determining the extent and thickness of passive fire protection (PFP) on offshore platform structures are simplistic and provide little opportunity for design optimization. This paper presents a review of alternative methods of determining the use of PFP which have been tried to overcome these disadvantages. The method progressed and used for North Everest and Lomond was based upon the modeling of credible fire scenarios, the calculation of steel temperatures and the progressive collapse analysis of topsides structure under rising temperature. The selected method allowed the design engineer to optimize the use of PFP while instilling confidence that the design met specified safety objectives.
Deriving Reservoir Pore-Volume Compressibility From Well Logs
Authors: Khatchikian Alberto
Published: June 2014

The bulk compressibility of porous rocks computed from the compressional and shear slowness and the bulk density from well logs using standard dynamic moduli formulas is not the equivalent of the static compressibility measured in the laboratory under hydrostatic load because of fluid stiffness effects predicted by the Biot-Gassman-Domenico model and the fact that the reservoir is under uniaxial rather than hydrostatic stress.

The method described in this paper derives a dry bulk compressibility from the "wet" dynamic value using the Gassman equation and reservoir parameters evaluated through log analysis. The pore-volume compressibility is then computed from the bulk and matrix compressibilities and the porosity. As this compressibility is obtained from sonic log velocities measured under uniaxial conditions of stress, field experience and laboratory measurements suggest that it is equivalent to the uniaxial compressibility, which is between one half and one-third of the hydrostatic-load value.

Application of this method to a consolidated sandstone and an unconsolidated sandstone/conglomerate compare favorably with pore compressibilities measured on cores, after conversion from hydrostatic to uniaxial stress conditions.
Modeling and Analyzing Pressure Buildup Data Affected by Phase Redistribution in the Weilbore
Authors: Xiao J. J. , Fuentes-N F. A. , Alhanati F. , Reynolds A. C.
Published: June 2014

This work describes the development of a simple mechanistic model to predict the effect that the transient two-phase flow of oil and gas has on pressure buildup data. Results from the model provide an improved physical understanding of the phase segregation process and how it influences buildup pressure data. The model is applied to obtain new physical insights into the variable wellbore storage models applied previously in pressure transient analysis.
Field Data Demonstrate Improved Mud Removal Techniques Lead to Successful Cement Jobs
Authors: Kelessidis V. C. , Guillot D. J. , Rafferty R. , Borriello G. , Merlo A.
Published: June 2014

Downhole zonal isolation requires the efficient removal of mud from the annulus and its replacement by competent cement. While good cementing practices have been developed over the years the results are not always satisfactory mainly because the techniques for mud removal are not optimized. Improved mud removal techniques have recently been developed which take into account quantitatively most of the parameters affecting mud displacement and cement placement. Application of these techniques has lead to considerable successes in the field. This paper provides further evidence of the effectiveness of these techniques by presenting the results of a field campaign.
The Influence of Heterogeneities on Well Test Pressure Response - A Sensitivity Analysis
Authors: Savioli G. B. , Bidner M. S. , Jacovkis P. M.
Published: June 2014

In the last decade many efforts have been devoted to obtain a more reliable prediction of reservoir behavior by including in the numerical simulators a better characterization of rock heterogeneities. In this paper we study the influence of permeability and porosity spatial variations on well test pressure response. With this aim, a numerical simulator of the oil flow towards a well, which includes radial variations of both properties, is applied. Field and synthetic data are analyzed. Heterogeneities are statistically characterized. Besides, constant estimates of permeability and porosity from well test pressure data are determined by applying a non-linear regression technique. We conclude that porosity may be considered constant in well test analysis while permeability variations must be taken into account, because they strongly affect pressure response. Power transformed permeabilities do not always follow a normal behavior; in fact, our field permeability data are better represented by an exponential distribution function.
EOR Polymer Screening for an Oil Field With High Salinity Brines
Authors: Leveratto M. A. , Lauri J. , Sanz C. , Sigal J. , Ali S. M. Farouq
Published: June 2014

Ten Polyacrylamides of different molecular weight and in different forms (powder, broth, emulsions) and three biopolymers were tested in order to evaluate their suitability for a EOR project in Catriel Oeste oil field in Rio Neg4ro province, with very high water salinity.

Screening involved: a) Resistance (RF) and Residual Resistance Factor (RRF) through fritted glass filters and viscosity measurement of solutions with different polymer concentrations, b) RF and RRF in actual pay zones cores with the selected polymers, c) ageing test at reservoir temperature, d) and oil recovery flood tests with final selected poliacrylamide.

Laboratory tests allowed a suitable Polyacrylamide to be selected and an optimal concentration of the solutions to be injected in the field chosen, which have been used for pilot test simulation and detailed design.

RF in actual cores gave satisfactory results.
A General Formulation of Linearization Methods Used In Reservoir Simulation with Applications to Adaptive Implicit Methods
Authors: Rodriguez Fernando , Bonet-Cunha Luciane
Published: June 2014

A general method to solve the set of nonlinear difference equations for multiphase flow in a reservoir is presented in this paper. Newton's method, applied to the fully implicit, FI, flow difference equations, is considered the general method from which classical formulations, IMPES, SS, SEQ, LSI, SI, are obtained in a systematic approach.

It is demonstrated, by decomposing the Jacobian matrix of the Fully Implicit method into a summation of matrices, [J]FI = [T] + [T′]p,S + [Pc′]+ [γ]p,S + [q′]p,S + [(ϕbS′)], that the Jacobian matrix of any formulation is a particular form of [J]FI. The level of implicitness of each method becomes evident from its Jacobian matrix composition, IMPES method possess the lowest implicitness, [J]IMPES = [T] + [(ϕbS′)], and Jacobians for any other formulation can be obtained by adding to [J]IMPES proper matrices taken from [J]FI.

The general method here presented is used to formulate an Adaptive Implicit Method, AIM. Corrections for implicitness are applied locally, at a gridblock level. Details of this procedure are discussed, along with the main points to consider when developing an AIM simulator.
A Semi-Implicit Formulation for Compositional Reservoir Simulation
Authors: Branco Celso M. , Rodriguez Fernando
Published: June 2014

A new semi-implicit formulation to solve the set of nonlinear difference equations that describe multiphase compositional flow in a reservoir is presented in this paper. Newton's method is applied on the nonlinear difference equations obtained after treating compositions in the flow terms explicitly, one iteration behind.

The linearized system of equations generated from this treatment possess a peculiar matrix structure, that allows the reduction of the system, via matrix operations, to three equations in three unknowns per gridblock regardless of the number of components.

The level of implicitness of the formulation presented in this paper is intermediate to IMPECS and Fully-Implicit methods and has a higher level of implicitness than a semi-implicit method previously proposed in the literature. It provides an attractive approach to solve problems where the rate of change of pressures, saturations and compositions in the reservoir are important, such that IMPECS method becomes impractical and the Fully-Implicit method becomes too expensive.

Applications to the simulation of a well-test in a gas-condensate well and the natural depletion and gas-cycling of a volatile-oil reservoir are presented.
Hydrocarbon and Produced Water Contaminated Soil and Pit Waste Remediation
Authors: Holliday G. H. , Deuel Lloyd E.
Published: June 2014

Exploration and Production [E&P] operations, worldwide, generate more soils and pit wastes contaminated with hydrocarbons, metals and chlorides than any other wastes, except produced waters. Transporting these contaminated wastes offsite results in operators losing control of the wastes. Additionally, transporting the wastes offsite consumes landfill capacity.

Field experience during the past 8–10 years demonstrates contaminated soils and pit wastes can be bioremediated onsite at low cost while retaining control of the waste. Moreover, bioremediation results in reducing hydrocarbon content to acceptable safe levels. Also, soil amendments convert sodic soils to calcium base soils encouraging leaching of the chlorides and revegetation of the affected area.

This paper presents remediation theory, amendments, limiting constituent criteria and mixing calculation techniques applicable to E&P operations. The authors illustrate land treatment and bioremediation technologies by providing a scenario detailing necessary data, calculations and limiting constituents required for successful remediation of crude oil and produced water contaminated soil.
Riser Gas Eliminators Reduce Wellhead Pressures on Offshore Satellite Platforms
Authors: Conner Stephen L.
Published: June 2014

E&P Exchange

Riser gas eliminators installed on the liquid export risers of five Gulf of Mexico platforms have significantly reduced wellhead pressure by releasing trapped gas. Wellhead pressures on the platforms have been reduced an average of 50 psi. The gas eliminators have been installed on lines in which the oil has undergone primary separation (gas/liquid) only and is being transported to another platform with separator pressure. Gas eliminators should be effective on other liquid lines in water depths of 50 ft or more, especially those with low velocities. The riser gas eliminator is an inverted steam trap installed at the top of the riser. The inverted steam trap has an internal float that allows the gas to vent through an orifice. The vented gas can be used for fuel supply or routed through the vent system.

Without a gas eliminator, abnormally high pressure in liquid lines can be caused by accumulated flash gas trapped in the export riser of the producing platform. Flash gas breaks out of the oil when it undergoes a pressure drop after leaving the separator. Under some conditions, this flash gas is not flushed out of the export riser and accumulates to fill the riser. This column of gas in the export riser must support the hydrostatic head of the liquid column of the receiving riser. Because the gas column has comparatively little density, the liquid pressure on the bottom of the receiving riser is transmitted to the top of the export riser, unnecessarily increasing separator and wellhead pressures. The abnormal pressure differential caused by the trapped gas is proportional to the height of the riser and the liquid density, and in some cases is greater than 100 psi.

Conditions under which the gas accumulates are controlled by a number of factors, including the amount of dissolved gas in the oil, the riser 10, the residence time in the riser, and the fluid velocity during the separator dumpcycle. Good candidates for gas eliminator installations are satellite platforms that export gas and liquid in separate lines, with the liquid line having the higher pressure. Actual pressure drops that are significantly greater than calculated frictional pressure drops are an excellent indicator of trapped gas.
Downhole Chemical Addition Owing to Convection in Annular Liquid
Authors: Babu D. Ram , Dhodapkar P.K. , Pradhan S.P. , Sharma A.N.
Published: June 2014

E&P Exchange

Production of waxy crude oils normally is associated with such operational problems as wax deposition in the tubulars and gelling of flowlines. In pumping wells, deposited wax restricts rod movement, leading to frequent breakdowns and production loss. Different methods are available to control wax deposition. Continuous addition of certain chemicals at low dosages to the well is popular because it reduces oil viscosity and other downstream problems. These chemicals, known as pour-point depressants (PPD's), remain in semisolid state at ambient temperatures. Pumping wells are treated by pumping a dilute solution of chemical and a solvent continuously into the casing through a macaroni line with the help of a dosing pump and a storage tank. During winter, the chemical solution needs more expensive solvents or heating to maintain its fluidity. To avoid the costs involved in the surface setup and its maintenance and monitoring, we tried a simple method in a few pumping wells with satisfactory results.

In this method, the oil column in the casing above the pump suction depth is replaced with a chemical solution. Density of the solution is maintained below that of the produced liquid. This prevents gravity swapping and ensures the presence of a chemical "reservoir" within the wellbore. The chemical batch is prepared by mixing PPD with heated lease oil of lower density and is displaced (Fig. 1a) into the casing/tubing annulus during the final stages of a hot-oil circulation operation.

When the pump is in operation, the temperature of the tubing's outer surface is a few degrees higher than that of the casing's inner surface. Natural convection currents occur in the liquid trapped between the two surfaces. The liquid rises along the tubing and moves in the opposite direction near the casing. Near the pump suction level, a constant exchange of mass between the crude entering the pump and the chemical reservoir takes place. With time, the concentration of chemical in the reservoir decreases and the density becomes equal to that of the produced liquid. The usual practice of venting the annular gas does not significantly affect this mechanism.
Obtaining Reliable Laboratory Measurements
Authors: Sprunt Eve S. , Humphreys Neil V.
Published: June 2014

E&P Exchange

Laboratory measurements on reservoir rock and fluid samples are required for many applications, including reserves determination, reservoir simulation, stimulation design, formation-damage assessment, and recovery monitoring. The costs of acquiring and testing samples are significant. Every attempt must be made to maximize the value added in making measurements. While the costs of laboratory measurements are small compared with the overall cost of field development, the financial impact is not. Decisions based on interpretation of the laboratory tests can make or break a project.

Before samples are acquired, define the goals of the measurement program.

. What are the business objectives in making these measurements?

. What are the consequences of not making these measurements?

. What business decisions will the measurements affect?

. What alternatives exist for obtaining these measurements?

. What are the consequences of making these measurements incorrectly?

The precision and robustness of commonly available measurements must be known to determine the nature of the data acquisition program. Balance the number of measurements and their accuracy. Unnecessarily narrow tolerances increase the costs of every step of the data-acquisition program. The objective may be reached more cost-effectively with a large number of qualitative measurements than with a few highly accurate ones. If measurement tolerances are broad, rule-of-thumb values may be adequate and new test data a luxury rather than a necessity. At the other extreme, small differences in measurements may critically affect decisions. Then, it may be necessary to customize existing testing procedures and develop new methods. Know the difference between the value of data and the cost.

Accuracy may not be constant over the entire measurement range. For example, measurements of permeabilities < 1 and 1,000 md are significantly less accurate than measurements of permeabilities in between. Consider the anticipated values for properties when designing an experimental program. Tests that may be accurate on a rock with a permeability of several hundred millidarcies and 20% porosity may be highly erroneous on a sample with <1-md permeability and 5% porosity.

Variances between different laboratories' measurements of basic properties are often larger than commonly assumed. If check samples are not used to ascertain measurement precision, unrealistically narrow limits may be cited. Laboratories fear that they will lose business if the competition claims greater accuracy.
The Gulf of Mexico Air Quality Study - An Industry Perspective
Authors: Shannon Brian E.
Published: June 2014

Section 328 of the Clean Air Act Amendments of 1990 required the EPA to promulgate a rule establishing air pollution control requirements for Outer Continental Shelf (OCS) sources. Congress exempted Gulf of Mexico OCS sources west of 87.5 degrees longitude (near the border of Alabama and Florida) pending the results of a "three year" study conducted by the Department of Interior (DOI) – Minerals Management Service (MMS). The study required an examination of the impacts of emissions from OCS activities in such areas that fail to meet the National Ambient Air Quality Standard (NAAQS) for either ozone or nitrogen dioxide. This paper reviews the MMS Gulf of Mexico Air Quality Study's (GMAQS) emission inventory development, historical ozone episode modeling, field sampling, and preliminary photochemical modeling results. Industry has developed a standardized spreadsheet to calculate emissions and a software package to allow operators to figure out the cost to control OCS sources for NO, and VOCs under the EPA's OCS Air Regulations (40 CFR Part 55). Cost estimates are provided for various regulatory scenarios currently being reviewed by the EPA and MMS.
Underbalanced Coiled Tubing Drilled Horizontal Well in the North Sea
Authors: Wodka Philip , Tirsgaard Henrik , Adamsen C.J. , Damgaard A.P.
Published: June 2014

Maersk Olie Og Gas AS has drilled a 3,309 ft long near horizontal drainhole with coiled tubing to a total measured depth of 11,000 ft in the Danish sector of the North Sea. The well was completed in May 1994 as a 3 1/2" open hole producer in the Gorm field chalk reservoir

Part of the well was drilled at underbalanced conditions with oil production rates of up to 1,100 stb/d during drilling. Conventional well test equipment was used for handling returns. A nearby process facilities platform supplied lift gas and received the produced hydrocarbons during the drilling phase.

Worth noting are the penetration of several chert layers, the fairly long reach, and the application of geo-steering Indications are that the well productivity is significantly improved compared to that of a conventionally drilled well, but problems were experienced with borehole stability in a fractured region.

Introduction

Maersk Olie og Gas AS (Maersk Oil) produce approximately 180,000 stb/d of oil from soft chalk reservoirs in the Danish sector of the North Sea. The largest producing fields have reached a stage, where the majority of the development activities concentrate on infill drilling and implementation of secondary recovery by means of water injection. Since 1989, development activities have almost exclusively been based on horizontal wells with a total of 78 wells drilled in five fields. Most of these wells are completed with a 7" cemented liner and perforated in multiple intervals with each interval straddled by 4 1/2" tubing (PSI system) for stimulation and production management purposes (Ref. 1 and 2).

As part of the continued efforts to produce the reservoirs in a cost effective manner and increase ultimate recovery, the emerging technology of coiled tubing drilling is seen as one possible method of obtaining low cost well re-entries, e.g for sidetracking and well extensions. It is recognized that the attractiveness of this technique depends on the long term production performance, including borehole stability, and the capability to decrease the costs, e.g. by performing the drilling operation from existing wellhead platforms on the relatively small wellhead platforms in the Danish sector, limited deck space necessitating placement of equipment on two bridge connected wellhead platforms and limited crane lifting capacity are the main problems in this respect

No field proven method had been developed for sidetracking from a horizontal well with a coiled tubing drilling assembly. Therefore, surface tests were initiated onshore in a coiled tubing test loop during August 1993. The objective was to test the technical feasibility of performing sidetracks and well extensions from existing horizontal 4 1/2" PSI completions with 3.688" restrictions. Several methods were tested, and a successful horizontal through tubing sidetrack was achieved already in the second attempt.
In Situ-Segregated Production of Oil and Water – A Production Method With Environmental Merit: Field Application
Authors: Swisher M. D. , Wojtanowicz A. K.
Published: June 2014

This paper describes field implementation of a new production method, the water drainage-production system for oilfields with bottom water coning problems. The method enhances the production rate of water-free oil while eliminating hydrocarbon contamina-tion of produced water.

The new method was used in a Wilcox sand in North Louisiana to resolve the problem of excessive water cuts experienced in conventional wells. Typically, for a conventional well in this area, a water problem would develop in 60–90 days after the beginning of oil production. The excessive water cut would cause a reduction of the oil rate from 35 BOPD initially to 12 BOPD with 97% water cut.

In this application a new well was drilled through the oil and water columns and dual-completed in both zones. The water-drainage completion (gravel packed) was isolated from the oil completion with a packer and 3-1/2" tubing. A downhole progressive cavity pump lifts the water in the tubing, while the formation pressure drives the water-free oil up the annulus between the tubing and 7" casing. To date, after 12 months of production, the oil production rate is averaging 45 BOPD, water-free.

Mathematical modeling was used to help in the design of the completion. Shown in this paper is a computer-generated analysis of the drainage-production system's performance. The analysis helped to determine the oil and water rates and geometry of the well's com-pletion.

Chemical analysis of water produced in the new method shows minimal contamination with polynuclear aromatic hydrocarbons (PAH), 11 parts per billion. This is an over 50-fold reduction compared to PAH contamination of water produced conventionally. Also, no contamination with Oil and Grease was measured with a detection limit of 2 mg/1.
Measurement and Enhanced Monitoring of BTEX and VOC Emissions from Glycol Dehydrators
Authors: Rueter Curtis O. , Reif Dirk L. , Menzies William R. , Evans Jarnes M.
Published: June 2014

The Clean Air Act Amendments of 1990 and activities by several states have resulted in increasing regulatory pressure on emissions of benzene, toluene, ethylbenzene, and xylenes (BTEX) and total volatile organic compounds (VOC) from glycol dehydration units. There are no standard sampling and analytical methods established by regulatory agencies for determining emissions from glycol dehydrators, and the methods initially used by the industry showed significant variability in results.

To address this lack of methods, the Gas Research Institute (GRI) began an effort to develop measurement methods and emission estimation techniques for glycol dehydrators. Ten methods were evaluated based on the criteria of ease of use, cost, and precision and bias in a series of field experiments at ten sites. The results of the project showed that GRI-GLYCalc™ should be used to initially screen a large number of units and that atmospheric rich/lean glycol measurements should be made to refine these initial estimates.

GRI has also initiated efforts to assist the industry in complying with enhanced monitoring requirements for glycol dehydrators. These enhanced monitoring protocols may be based on using condenser temperatures in conjunction with computer programs such as GRI-GLYCalc. Additional test data will be collected using the methods developed in the previous efforts to validate the computer program predictions for condenser control efficiencies.
The Mitigation of NORM Scale in the Gulf Coast Regions of Texas and Louisiana: A Laboratory and Field Study
Authors: Oddo John E. , Zhou Xinliang , Linz David G. , He Shiliang , Tomson Mason B.
Published: June 2014

Some oil field scales have the potential to contain regulated levels of naturally occurring radioactive materials (NORM). It is estimated that between 300,000 and 1,000,000 tons of NORM scale are produced each year. In addition, scale deposition in producing facilities negatively impacts rates of production and is expensive to treat and remediate. The most common NORM containing scale is BaSO4, or barite. This paper presents the results of a Gas Research Institute study that investigates the causes of NORM scale formation and mitigation techniques employed in the field.

Chemical threshold scale inhibitors are generally employed to inhibit scale formation in production systems. However, there is little agreement on which scale inhibitor is most effective with respect to differing water chemistries, temperatures and conditions encountered. Results using a GRI patented inhibitor evaluation apparatus can be used to determine the most effective inhibitor for a specific field application. Work in the Michigan Basin presented in the last conference indicated that a phosphinopolycarboxylate was most effective against NORM barium sulfate scale formation at low temperatures in relatively fresh water. Further work in this study identifies phosphonates as being more effective in the higher ionic strength (TDS) waters and higher temperature regimes that can be expected in the Gulf Coast. A matrix of ionic strength and temperatures with inhibition response is presented.

Although more NORM fields were studied, two are presented in detail. In these fields, three causes of NORM scale were identified; 1) Incipient scale in a well due to production; 2) Scale formation due to previous seawater floods and; 3) The commingling of waters from different zones or wells. Field treatment techniques employed in the two fields studied are summarized in the paper.

Inhibitor squeeze procedures were also studied in the laboratory and in the field. A squeeze simulation apparatus was constructed to research inhibitor squeeze practices in the laboratory. Results from this work resulted in successful inhibitor squeeze applications in the field. The inhibitor squeeze apparatus and the field results are discussed in the paper. Squeeze life has been extended from an average of two to six months to two to three years or more as a result of the work.
Application of an Area of Review Variance Methodology to the San Juan Basin New Mexico
Authors: Dunn-Norman S. , Warner D. L. , Koedoritz L. F. , Laudon R. C.
Published: June 2014

When the Underground Injection Control (UIC) Regulations were promulgated in 1980, existing Class II Injection wells operating at the time were excluded from Area of Review (AOR) requirements. EPA has expressed its intent to revise the regulations to include the requirement for AOR's for such wells, but it is expected that oil and gas producing states will be allowed to adopt a variance strategy for these wells.

An AOR variance methodology has been developed under sponsorship of the American Petroleum Institute1. The general concept of the variance methodology is a systematic evaluation of basic variance criteria that were agreed to by a Federal Advisory Committee. These criteria include absence of underground source of drinking water (USDWs), lack of positive flow potential from the petroleum reservoir into the overlying USDWs, mitigating geological factors, and other compelling evidence.

The AOR variance methodology has been applied to oilfields in the San Juan Basin, New Mexico. This paper details results of these analyses, particularly with respect to the opportunity for variance for injection fields in the San Juan Basin.
Development and Practice of Separate Layer Production Technique in Daqing Oilfield
Authors: Wang Zhou , Chaoyang Xie , Jingshen Li , Fengshan Wang
Published: June 2014

This paper describes development and applications of separate layer production technology, which facilitates full exploitation of the potential of each oil-bearing layer. The technology has evolved as water cut has increased in Daqing oilfield and focus has shifted to thinner, lower productivity layers. In Daqing field, 11 kinds of separate layer water injection strings, which can be divided into two main categories (hydraulic inflatable and compressional), 33 kinds of separate layer production (water shut off) strings divided into four main categories (including integral, slip support releasing, drill-able and pressure balance), four separate layer fracturing techniques (including sleeve separate layer, limited entry completion, multi-frac and positioning balance) have been developed.
Casing Repair Technique by Explosive Welding
Authors: Gui Yu , Bangjin Xie , Xuechang Zhao
Published: June 2014

This technique including explosive reforming and explosive welding is mainly adopted for repairing downhole damaged casing in an oilfield. It is based on the principle of explosive action to restore a deformed casing and to weld the damaged section.
A Study of Infill Pattern in the Later Period at High Water Cut Stage to the Main Reservoir in the Central Portion of the Saertu Pool
Authors: Shiyuan Zhao , Hongyin Gao , Hongfu Jiang
Published: June 2014

The main reservoir of the Daqing field, the PI reservoir, was evaluated after total water cut had increased to about 90%. The location of high residual oil saturation was correlated with the depositional environment. Recompletion and redevelopment plans were formulated for each lithology. Wells were selectively perforated and additional infill wells were drilled. Finally, a polymer flood was initiated. It was concluded that the reservoir should be perforated twice to increase the volume swept by waterflood before injecting polymer.
Variations of Petrophysical Parameters After Sandstone Reservoirs Watered Out in Daqing Oil Field
Authors: Hongxing Zhang , Qingnian Liu , Fengqin Li , Yingping Lu
Published: June 2014

Based on lab data this paper summarizes differences of petrophysical parameters of sandstones in Daqing Oil Field which were not watered out before waterflooding and were watered out after waterflooding. Pore throat dimensions, relative permeability, and wettability change with prolonged waterflooding. Using internal waterflooding at an early stage is a method of maintaining the reservoir energy and achieving long — term high and stable production. Injecting a great quantity of water for a long time is an effective means of enhancing oil recovery of reservoirs for Daqing Sandstone Oil Field.
Field Test of Immiscible CO2 Drive in Daqing Oil Field
Authors: Jingcun Zhang , Shangxian Xie , Peihui Han , Jiabao Chen , Zhenghua Zhang , Encang Guo
Published: June 2014

The choice of water alternate carbon dioxide flooding in Sanan was decided based on prefeasibility studies on EOR methods suitable for Putaohua reservoir in Sanan area of Daqing Oil Field. This process was first implemented on one pilot, before any industrial extension. This paper introduces the pilot test, evaluates the effects of CO2 drive and analyzes behavioral characteristics of the test.
Relationship Between Reasonable Injection-Production Ratio and Pressure Level in Development Area of Southern Saertu Reservoir, Daqing Oilfield
Authors: Qixin Li , Yuzhuo Wang , Huanzhong Dong
Published: June 2014

Using the principles of seepage mechanics, this paper analyzes the interrelationship between formation pressure and injection - production ratio and the influential factors. On the basis of a mechanical study, it quantitatively analyzes the pressure history of each area by means of a mathematical statistic method and the controlling factors, and the effect of every factor on formation pressure. It furnishes a scientific basis for the effective and rational control of the Southern development area of the Saertu Reservoir and each sub-area.
The Discrete Newton Method of the Three Parameters Inversion in Electrical Logging
Authors: Yang Cao , Jiaqi Liu , Wei Yang , Yousheng Fu
Published: June 2014

Log analysts are always interested in the problem of determining the invaded zone resistivity, Rxo, the virgin formation resistivity and the diameter of the invaded zone, D, simultaneously, using the logging tool responses of the deep and shallow laterolog 3. In this paper, the problem of multiple parameter identification in electrical logging is reduced to a partial differential equation. Using the Discrete Newton method and the regularization method, the mathematical formulas of inverting three parameters are derived. Thus, an iterative method of simultaneously solving Rxo, RT and D is obtained.

To test this method, some numerical computations have been made. The computational results show that when no noise is added, the mean relative errors of inverting Rxo, RT and D are 0.67%, 0.47%, and 2.28%, respectively. When 10% noise is added to the resistivities of the adjacent formation, the mean relative errors are 2.65%, 0.92%, and 5.39%, respectively. This method has been used to deal with the real measured data. This method can be used widely to direct log interpretation and eliminate the interpretation chart.
Monitoring and Controlling of Oil and Gas Cross Flow During Production of Daqing Lamadian Laminated Oil Field with Gas-Cap
Authors: Baofa Ji , Zhengshun Xu , Jianxin Wang
Published: June 2014

Daqing Lamadian oil field is the largest oil field with a gascap in China. Monitoring, controlling and adjusting techniques have been used extensively to minimize cross flow. An inverted nine-spot pattern was used in the oil-bearing area. Gas-bearing layers were not perforated and there was a 400 to 600m buffer zone of oil and gas migration left between oil-and gas-bearing areas. A monitoring system for gas-cap performance was established. Flow between the oilbearing and gas-bearing layers has been successfully controlled and a relatively stable oil-gas interface has been maintained for 20 years.
Mechanism of Cyclic in Waterflooding in Vertically Heterogeneous Reservoirs
Authors: Qingfeng Yuan , Bingyu Ji , Jiping Yang
Published: June 2014

From Darcy's law of two phases (oil and water), an analytic expression for oil and water vertical cross flow including gravity cross flow, capillary cross flow and additional cross flow under the effect of cyclic waterflooding is developed. Based on function J, this paper analyzes the vertical cross flow characteristics of capillary and its influence on production, explains the essential distinction between cyclic waterflooding and conventional waterflooding.
High Integrity Pressure Protection Systems For Production Applications
Authors: Langvik S. , Aarebrot E.
Published: June 2014

Through the use of a High Integrity Pressure Protection System (HIPPS) the flare capacity of a wellhead platform can be reduced to the flowrate required for depressurisation. The HIPPS may also be used to reduce the flare capacity of a process plant. By the use of HIPPS, the discharge of hydrocarbons or carbon dioxide due to venting/flaring is reduced.

This paper describes the development of HIPPS for the Sleipner B-platform offshore Norway. A 20" multiphase pipeline is protected against overpressure by two 20" quick acting shut down valves (QSV) installed in series, instead of pressure safety valves. The valves have been qualified for operation in wellstream at a shut-in pressure of 336 bar, and have a closing time of 2 seconds. Each of the QSVs has independent, fail safe instrumentation cirquits. A parallel train of QSVs has been installed due to the testing requirements. The estimated saving using HIPPS on SLB was $ 25 mill.

The paper also discuss existing and new applications of the HIPPS.
Impact of Uncertain Oil Prices on Investment and Integration Efforts in the Oil and Gas Industry
Authors: El Banbi Hamdi
Published: June 2014

A rapid review of the energy resources situation in the world today shows the important role that oil and gas play in human life. World economies will continue to rely on oil and gas as a major energy source. It is absolutely critical that policy makers - governments, investment decision makers, and oil companies - cooperate in securing a supply of energy for future generations.

The international oil industry, in its sustained efforts to optimize resources in a cost-conscious and challenging environment, has been working under several constraints: reduction in investments, environmental issues and policies, and workforce optimization. This paper highlights recommendations for facing these challenges.

Introduction

The current world energy resources emphasize the importance of oil and gas in the world energy market.Coal, beside wood, is the oldest known fossil source of energy and contributes about 27% of today's world primary energy consumption. Coal has to be cost competitive with oil and is less practical for everyday use than gas. In addition, coal is less competitive than oil and gas because of the environmental impact its extensive mining and burning. Coal's share of future total world wide energy is expected to stagnate or even drop below current levels.Hydroelectric resources account for 2.5% of worldwide energy utilization. Room could exist for some expansion, depending on investment in new hydraulic projects.Nuclear energy, which represents about 7% of the world's energy consumption, needs further technical progress to overcome serious environmental and safety concerns.Renewable resources, such as solar and wind energy, make up a fraction of 1% of the total energy consumption. These renewable resources are exotic and require further development to solve technical and practical problems before they can compete reasonably with oil and gas. While not yet available on an industrial scale, they can have an important place in unique, yet small, applications.Oil and gas are and will remain, by far, the principal sources of energy for the foreseeable future. Alone, they supply about 63% of the world's primary energy. Worldwide, gas reserves seem more geographically diverse than current oil reserves. Also, gas reserves have been developing at a faster pace during the last 2 decades. If gas reserves continue to develop at such rates, they will surpass those of oil in the not very distant future.
Advances in Cement-Plug Procedures
Authors: Heathman J.F.
Published: June 2014

Operators set cement plugs for a variety of reasons: abandonment, sidetracking, lost-circulation control, or remedial work. However, as important as plug cementing can be to the overall success of a well program, the process often is performed without regard to wellbore conditions. The additional rig time and material costs quickly add up as multiple plugs are set. The industry average is approximately 2.4 attempts per kickoff. Studies have highlighted many of the problems encountered in plug cementing. Implementation of systematic, controlled procedures has established a near 100% success rate where used for establishing kickoff plugs.

Recommended Plug Procedure

Recent work has determined that cement plugs require the same degree of planning as primary cement jobs, plus special considerations for plug stability. A joint team of operators and a cementing service company evaluated the problems and mechanics of plug cementing. The team developed a recommended plug procedure (RPP) to alleviate problems. The procedure provides a reliable plug-setting procedure and develops a method to monitor success rates. The RPP addresses communication, temperature estimation, mud removal, slurry design, slurry volume, and plug stability. Understanding the relationships between these variables is vital to the success of spotting a balanced cement plug.

Job Design

Communication. To design a cement-plug job properly, communication among all personnel responsible for the job design is essential. It is important that personnel discuss options for each job so that assumptions are not made about equipment availability and/or capabilities. Sharing data from the field is also important. Detailed pre-/postjob data sheets have helped to build a database that has been instrumental in finding the causes of both successes and failures.

Temperature Estimation. One of the most important design variables is placement time, which is governed by pumping rates and bottomhole circulating temperatures. In most cases, little attention is paid to plug-cementing temperatures; most laboratories use published cementing schedules. At times, temperature estimates are also adjusted upward to increase the safety factor, resulting in over-retardation. The use of computer simulation or temperature surveys for temperature predictions can help ensure that the slurry will not be over-retarded. Also, a more realistic waiting on cement (WOC) time can be estimated if compressive-strength thermal-recovery schedules are slow enough to match wellbore conditions, reaching American Petroleum Inst. bottomhole static temperature only after 24 to 36 hours have elapsed.
Results From the Heidrun Field Cased-Hole Gravel Packs
Authors: Landrum W.R. , Burton R.C. , MacKinlay W.M. , Erlandsen Aasmund , Vigen Arild
Published: June 2014

During the initial phase of the Heidrun field development, five wells were precompleted with state-of-the-art cased-hole gravel-packing techniques. The wells were tested and temporarily abandoned, awaiting tieback to the Heidrun tension-leg platform (TLP). This paper describes the completion techniques applied and presents results of an evaluation of gravel-pack efficiency for the wells. Flow and buildup tests were carried out on the semisubmersible drilling rig before and after gravel packing to evaluate initial productivity. Stabilized well-test data acquired on the Heidrun TLP at full production are presented to document ultimate completion performance for each well.

Innovations

Perforating with tubing-conveyed perforating guns on a drillstem-test (DST) string allowed perforating, perforation cleanup and flowback, pre-gravel-pack testing, and gravel prepacking to be performed in a single run. A unique loss-control-material (LCM) formula was developed and applied to control fluid losses to the formation. Prepack modeling and alternating stages of clear brine and slurry were used to optimize gravel placement. A temporary-abandonment system was developed and installed that used a weight-actuated ball valve to abandon the well temporarily without placing any damaging fluids across the production zone. Gravel-pack screen assemblies included alternative-path gravel placement with four shunt tubes per gravel-pack screen assembly.

The innovative gravel-packing techniques used at Heidrun resulted in high completion productivity and correspondingly high flow rates. A study performed to evaluate the economic impact of acceleration showed that going from a 20,000- to a 30,000-BOPD well rate added $108 million in pretax net present value to Heidrun project economics. Actual results will be greater because well rates have exceeded 43,000 BOPD.

Introduction

The Heidrun field lies 120 miles offshore mid-Norway in the Haltenbanken area in approximately 1,140 ft of water in the Norwegian Sea. Hydrocarbons were proven in three main reservoirs of Jurassic age: the Middle Jurassic Fangst group and the Lower Jurassic Tilje and Are formations. Fig. 1 provides a type log. The field is being developed from the world's first concrete-hull TLP. Ten wells were predrilled from the main 56-slot template along with six subsea, seawater injection wells drilled from the two four-slot satellite templates. First oil production occurred on Oct. 18, 1995. The Heidrun TLP is currently producing at plateau rate of more than 230,000 BOPD.
Natural Gas Transportation Issues
Authors: Adewumi Michael A.
Published: June 2014

The Increasing Role of Natural Gas

Gas has arrived in a big way. Or has it? While it already plays a significant role in the current energy picture, all signs point to natural gas as the energy of the future. In 1995, U.S. gas demand growth outpaced that of total energy consumption by almost three to one. Predictions are that U.S. gas consumption will increase to a record 23.48 quadrillion Btu in 1996, a nearly 3% rise from 1995. It is also estimated that Canadian gas consumption will grow at twice the rate of that of the U.S. The rapidly increasing role of natural gas is motivated by its clean-burning characteristics, its relative abundance, and its wide geographical distribution. In response to this increasing demand, many large gas development projects are under way in Southeast Asia, South America, and Africa. It is therefore no wonder that several recent articles, reports, and editorials have heralded the dramatic arrival of natural gas on the energy stage.

While the current rapid rise in gas consumption is attributable to its increasing popularity in traditional usage, the impending popularization of natural gas vehicles (NGV's) should guarantee such a trend in the future. For many years, natural gas has been touted as competing with oil only as a non vehicular energy fuel. This will change. High-population states in the U.S., such as California and New York, are already converting their mass transportation systems from oil-based to gas-based. This is a growing trend in the urban areas. Europeans are also changing. In a recent, rather bold move, industry officials from 17 countries formed the European Natural Gas Vehicle Assn. The aim of this association is to globalize the use of natural gas as a vehicular fuel. With the popularization of NGV's, diverse and sustained utilization of natural gas is ensured.