bluuebunny/crossref_metadata_2025 huggingface dataset:
High-Speed & High-Efficient Development of an Extra-shallow Sea Oilfield
Authors: Sun Huanquan , Wang Shiyan
Published: December 2007

Chengdao oil field is a large oil-gas field, which is situated in a very shallow water area of Bohai Bay of China. According to the complicated maritime and geological situation, the compositive study method containing several kinds of appropriate new techniques has been applied in the course of researching work on the geology and engineering situation of the reservoir. For example: The technique of logging constraining seismic inversion has been applied to predict the fluvial sand body's scales. As a result, the coincidental rate of the total number of layers up to 88% and the coincidental rate of the total thickness up to 92%.On the base of the study in pilot test area, multiple techniques, such as reservoir simulation and economic evaluation, have been applied to optimize the developing plan and preserve the pressure levels of the reservoir. It can also be used to determine the reservoir productivity and predict developing project parameters. The coincidental rate of reservoir productivity is 97.8%.The application of enlarging well spacing and irregular well sites aiming at the main oil-hearing sand bodies has saved investment and improved economic efficiency.

The project of Shengli offshore oilfield productivity building has been established on the base of compositive study on the reservoir geology. It contains 33 Well Group, 119 wells totally. The successful ratio of drilling is up to 100% and the accumulated productivity is up to 2,480,000 tons. By present, a set of techniques appropriate to the development of very shallow water oil field has been formed and the high-speed and high-efficiency development of Chengdao oil field has been achieved by using it.
New Formula of Surge Pressure for Determining Safe Trip Velocities
Authors: Rubiandini R. S. Rudi
Published: December 2007

Operational problem that related to tripping in/out pipe or running casing into the well bore become more severe and complicated, as drilled hole get deeper and smaller4).

When the pipes or casing are run into the well bore with high velocities, it will produce high surge pressure (increasing hydrostatic mud pressure) in the well. If the maximum fracture gradient limits were exceeded, the formation would be fractured and would end up with lost circulation. At the same time, when pulling out pipe from the drilled hole with high velocities, it produced high swab pressure (decreasing hydrostatic mud pressure) in the hole which lead to kick. If the minimum pore pressure limits were exceeded, there would be a flow of formation fluid into the well bore.

Based on this condition, we need the optimum safe trip velocities by predicting the surge pressure in the hole to prevent the possibility of kick or lost circulation without forgetting the operating time saving factor.

The paper developed some of new simple formulas for determining surge pressure as a function of pipe velocities parameter, mud properties, pipes and hole sizes diameter.

The analysis and variation process using a range of data that commonly used in the field. Using a computer, combination of mud properties, pipe and hole sizes had been done to evaluate the approximate equations for the conditions most often encounter in field operation.

The result are some new simple formulas of surge pressure which are a function of moving pipe velocities that are corrected by plastic viscosity parameter, yield point, mud density, pipes and hole size diameter for many common condition in the field. Compared with Moore formula which not involving pipe velocities parameter, plastic viscosity and mud density would lead to inaccuracy of predicting the surge pressure. With Burkhardt formula that used a graphic in calculation, it was not efficient for field used and it could cause a human error when plotting the graphic. Theoretically for pipe velocities ranging from 20 - 600 ft/min, it was found that these formulas have a good accuracy and the most important think is the simplicity for field operation. Although there are some formulas that had been published, which use an iterating process in predicting the surge pressure for better accuracy, it is not efficient enough for engineers in the field because of its complexity.

Based on these formulas, the possibility of kick and lost circulation in tripping process or running a casing could be prevented by predicting the optimum safe trip velocities and also saving in time and operational cost.
Keys to the Successful Application of Hydraulic Fracturing in an Emerging Coalbed Methane Prospect - An Example from the Peat Coals of Australia
Authors: Badri M. , Dare D. , Rodda J. , Thiesfield G. , Blauch M.
Published: December 2007

Early stimulation work in Peat Field of Queensland, Australia involved application of cavity completion techniques to produce methane gas at commercial rates in the first wells completed in the reservoir gas cap. Early in the project life, cavity completion treatments resulted in promising and acceptable gas flow rates. However, excessive cost associated with this technique led to consideration of alternate stimulation approaches by the design team. The main objective was to achieve similar or better gas rates at the lowest cost.

Multi-seam nitrogen-foam stimulation was conducted in several wells of the Peat field to assess the effectiveness of this technique in terms of: (1) production enhancement and cost reduction; (2) location of the coal-seam intervals in the gas cap (i..e. gas-saturated coals) and; (3) improved completion efficiency.

To minimise the effects of tortuosity and multiple far-field fractures in addition to ensuring that each coal-seam interval received adequate treatment, a staged stimulation approach in combination with other remedies such as sand slugs and high injection rates was adopted and successfully applied.

Zonal Isolation was achieved through the use of the newly developed, easily drillable composite plugs that allow staged treatment with flowback capabilities.

Field data of representative Peat wells will be used to demonstrate the successful application of the hydraulic fracturing approach that resulted in methane gas rates that more than compete with the early cavity completion techniques either from a cost or production improvement point of view.

The following specifics are addressed in the paper: A novel fracture design approach and modeling of fracturing treatments that can be of value to a broad audience of operators and design engineers.Real-time fracture stimulation methodology, analysis, and execution.Remedies to minimize the near-wellbore tortuosity and multiple far field fractures to avoid premature "screenout" and carry the fracture treatment to completion.Chemical optimization of fracture fluid designed based on coal characteristics.Use of newly developed composite epoxy-glass fracture and bridge plugs that provide a more efficient and cost effective way to carry out staged stimulation treatments.Post-fracture production tests to estimate the nitrogen- foam fracture treatment effectiveness in multi-seam CBM wells.
Intervention in Wells with Buckled Production Tubing
Authors: Newman K. , McSpadden A.
Published: December 2007

Sometimes the production tubing in a well can be helically buckled due to problems with the completion design, completion hardware, or installation problems. When coiled tubing (CT), wireline (WL) or jointed pipe (JP) is run through helically buckled production tubing there is a significant risk of getting stuck. This paper discusses the impact of helically buckled production tubing on the forces required to perform an intervention in the well. The theory for these forces is discussed, and a practical example is presented.

Introduction

Production tubing that is in compression, and is thus helically buckled, is common. Though the production tubing is initially hung in tension, the increase in temperature due to production from the well sometimes causes the production tubing to compress and buckle. In other cases there is not enough tension applied when the well is completed, allowing the bottom portion of the production tubing to buckle.

When any through tubing intervention is performed in a well with buckled production tubing, care must be taken to avoid becoming stuck. Since this paper is being written for a CT conference, it will focus on CT intervention, but it is important to note that the same concepts apply to WL and JP.

The helical shape of the production tubing, and thus the intervention path, causes increases in the tension or compression due to the capstan or belt friction effect of the helical shape. This effect may cause the tension to reduce while running in the hole (RIH). As long as the CT does not go into compression (in which case it will likely lockup, preventing any further penetration into the well), the operator will simply see a reduced weigh reading on surface. However, upon picking up weight to pull out of the hole (POOH), the increased tension due to the capstan effect may be greater than the breaking strength of the CT. Thus, the CT can be RIH but can become stuck when trying to POOH.

Theory

The buckled production tubing causes a modified form of the "capstan effect" sometimes known as the "belt effect". The increase in tension or compression due to this effect can be expressed as:Equation 1.1

Equation 1.1 must be included with the other vector forces due to gravity and wellbore curvature in a tubing forces model (TFM) for practical use. The period of the production-tubing helix will vary along the length that is buckled. The TFM must be run for the production tubing to determine the period versus depth in the well.
Hydraulic Pumping Units for Offshore Platform
Authors: Zhou Zhiqi , Hu Chen , Song Kaili , Li Xinhua , Gao Guangqi , Yang Juanhua , Fan Chunyu , Feng Hui
Published: December 2007

This paper introduces a hydraulic pumping unit for offshore platform that has been developed by Shengli Petroleum Administration and successfully applied to the oil field. This pumping unit adopts closed return circuit. In order to reclaim power and save energy, two sets of accumulators are set respectively at the entrance and exit of the hydraulic power pump. The energy is stored in the accumulators during the down stroke and the stored energy is released to lift the oil well load during the lift stroke. This pumping unit adopts the unique full hydraulic reversing and controlling return circuit, the hydraulic cylinder is set in the working barrel under the wellhead. In order to collect the signal of the piston arriving the top and bottom dead center, the both stroke holes are set in the inner tube of the hydraulic cylinder. The wellhead's installation area and height are equivalent to the flowing wellhead's. The height of this wellhead is less than 3 meters measuring from casing head. The structure of the hydraulic station is compact, the area that it contains is small, so it can be used on the offshore platform which area is limited. By developing of the hydraulic pumping unit for offshore platform, the mature technology in sucker rode oil production mode will be applied to offshore oil production, its application will greatly extend well repair cycle and obtain enormously economic benefit.
Experimental Investigation of CO2 Gravity Drainage in a Fractured System
Authors: Li Hujun , Putra Erwin , Schechter David S. , Grigg Reid B.
Published: December 2007

Traditionally, CO2 injection has been considered an inefficiënt method for enhancing oil recovery from naturally fractured reservoirs. Obviously, it would be useful to experimentally investigate the efficiency of waterflooding naturally fractured reservoirs, followed by CO2 injection, before this procedure is applied to a reservoir. This issue was investigated by performing water imbibition followed by CO2 gravity drainage experiments on artificially fractured cores at reservoir conditions. The experiments were designed to illustrate the actual process of waterflooding and CO2 gravity drainage in a naturally fractured reservoir in the Spraberry Trend Area in west Texas, USA.

The results demonstrate that CO2 gravity drainage could significantly increase oil recovery after a waterflood. During the experiments, we also examined the effects of different parameters such as permeability, initial water saturation, and injection schemes. We found that the efficiencies of the CO2 gravity drainage decrease as the rock permeability decreases and the initial water saturation increases. Cyclic CO2 injection helped improve oil recovery during the CO2 gravity drainage process after water imbibition.

Oil samples produced in the experiment were analyzed using gas chromatography to determine the mechanism of CO2-improved oil production from tight matrix blocks. The results show that lighter components are extracted and produced early in the test.

The results of these experiments validate the premises that CO2 will recover oil from a tight, unconfined Spraberry matrix.
Reservoir Characterisation and Evaluation of Micaceous Sandstone of Geleki Field, Upper Assam, India - An Integrated Study
Authors: Kumar Pardeep , Sharma S. C. , Roy U. S. , Sud V. K.
Published: December 2007

Tipam sandstone, the main hydrocarbon-producing reservoir of Geleki Field located in Upper Assam, India, is of highly complex nature containing good amount of mica (Muscovite) in addition to quartz, feldspar and montmorillonite as inferred from sedimentological studies. Mica complicates log analysis as most lithology indicators reflect it as high-density shale, resulting in pessimistic reservoir evaluation.

Mica is often misinterpreted as shale by common clay indicators used in conventional deterministic interpretation models based upon Density-Neutron-GR logs. However, mica should be considered as structural part of the rock not affecting porosity and permeability. Surface of mica is altered by diagenesis and acquires surface conductance leading to reduced resistivity of the formation even at constant porosity. Therefore, if mica is not included in lithological model the evaluation can be misleading. Further, high computed shale volume will make good reservoirs either appear worthless or with reduced potential.

In the present paper, the influence of mica on various log responses has been analysed, based upon which a highly micaceous sandstone facie has been identified in the upper portion of the reservoir. However, presence of mica and feldspar in moderate proportions is inferred throughout the formation. Multi-mineral interpretation model based upon statistical inverse modeling technique has been successfully used for realistic evaluation of reservoir parameters leading to identification of new hydrocarbon bearing layers.

Oil production from a well tested on the basis of the present integrated study has confirmed the efficacy of the suggested model. Extension of the model to other similar reservoirs can lead to better reservoir characterization and delineation of by-passed hydrocarbons.
Investment and Risk Analysis Applied to the Petroleum Industry
Authors: Motta R. , Caloba G. , Almeida L. , Moreira A. , Nogueira M. , Cardoso L. , Berlink L.
Published: December 2007

In Brazil, for the last four decades, Petrobras, a state-owned company, had retained a monopolistic concession for the exploration of Oil & Gas prospects, when, in 1998, the law was changed and a broad range of opportunities were created. Since then, Petrobras has been offering a series of Join Venture opportunities for foreign oil companies to farm in.

Presently, a number of international oil companies installed offices locally and started to participate in the upstream sector. ANP, the National Petroleum Agency, is offering for tender various blocks both offshore and onshore. The first bid round was a major success, in mid 1999, the second bid round being scheduled for the third quarter of year 2,000.

Blocks leased in the first bid round are now being explored by means of 2D and 3D seismic, and the first exploratory wells will be soon drilled.

This article presents a framework to perform an economic evaluation of oil & gas prospects, taking into account the risk factor. The Net Present Value of each block is first computed based upon an average value. Following that, Monte Carlo simulation is used to compute the downside risk. The inputs are determined by means of probability distributions. Reservoir parameters, capital and operating costs and oil prices are fed into the program, revealing the NPV sensitivity to each factor.

The problem is further structured by means of decision trees. The Expected Monetary Value, based upon perceived probabilities of success, is estimated, utility functions being used to account for risk aversion. The optimum level of participation in each prospect is determined, using the so- called Certainty Equivalent concept. Finally, the formation of an optimum portfolio is discussed, so that any oil company can establish its strategy in joint bids and farm ins.

Four hypothetical prospects are evaluated; with different levels of investment and risk profiles, namely, from higher probability of success to new frontier, lower probability of success. The correspondence with real life may be, respectively, the Campos Basin, where 70% of Brazilian oil production comes from, and basins like Pelotas, where there are no producing wells, with little seismic available.

The framework suggested in this work could be useful for any company that is currently involved with exploration activities. Additionally, it may be used for analyzing any investment with a certain degree of uncertainty or volatility.
Development of an Active Global Lessons Learned Database - LINK
Authors: Dewhirst Neil W. , Evans David C. , Chalfont Simon , Jobson Nigel
Published: December 2007

During 1999 BP Amoco developed an intranet based global lessons learned database for use by its well construction and operations teams. This tool, named LINK, was implemented in the +/-50 wells teams during 1Q 2000. There was business drive for the development of a tool that facilitated learning between teams without imposing any additional workload. Passive tools existed, but were mainly for use within single teams and were not easily accessible by anyone outside the team. The prize was in making it possible for wells teams globally to learn continuously and simultaneously.

LINK is designed to help teams deliver a significant, sustainable performance improvement in several ways: It provides each team with a lessons learned knowledge base and action tracking system to support continuous improvement.All users enter and access data in a consistent way, allowing all that is learned by BP Amoco wells teams to be easily accessible to everyone.It actively promotes connectivity between teams, ensuring that knowledge is disseminated throughout the community.

The active functionality ensures that teams are automatically made aware of what analogue teams have learned, both positive and negative. The system sends high value lessons to the relevant teams and communities of practice. The philosophy is that when engineers are made aware of what someone else has learned, if it is relevant to their operation and of high value, then they will act upon it locally, maximising the federal benefit of that knowledge.

LINK has become the global platform to disseminate high value learnings (including stuck pipe, well control, equipment failure, and HSE incident reports). Although LINK was developed for use in well operations, interest has been shown by other disciplines within the company. For example, Project Engineering, Petrophysics, & Geophysics are considering making use of the platform to facilitate similar collaborative learning behaviours resulting in improved performance in their areas.
Tracer Simulation to Improve the Reservoir Model in the Snorre Field
Authors: Ali E. , Chatzichristos C. , Aurdal T. , Muller J.
Published: December 2007

This paper presents the application of water tracer flow simulations as a means for better characterization of the Central Fault Block (CFB) reservoir in the Snorre field in North Sea. The simulations of the tracer flow were carried out using a numerical model, developed by the Institute for Energy Technology for modeling of tracer flow in porous media, coupled to CMG-STARS chemical/thermal simulator. The tracer data was first analyzed to establish reservoir continuity between three injectors and six producers in the fault block. Then, tracer flow simulation results were matched with measured tracer field data in order to improve the history match of the water cut in the reservoir model.

History matching of tracer production profiles is presented together with history matching of water cut before and after the consideration of tracers to highlight the improvement of the reservoir model.
Stability and Rheological Behavior of Aqueous Foams for Underbalanced Drilling
Authors: Rojas Y. , Kakadjian S. , Aponte A. , Márquez R. , Sánchez G.
Published: December 2007

This paper presents evaluations of stability and rheological behavior of aqueous foam formulations. The stability of these systems was evaluated by the Ross-Miles method, using half-life measurements, and was studied as a function of the type and concentration of surfactants, polymers and salts. The effect of contaminants such as crude oil is also examined. A capillary tube viscometer was used to perform the rheological studies. The effect of variables such as quality of the foam, pressure system, tube diameter and polymer type is shown. Results were corrected for wall slip effect and normalized by using equalized volume corrections.

Results indicated that the sensitivity of the foam to contamination with oil and salts depends on the chemistry of the foaming agent system and crude oil used. The rheological evaluations showed that the flow behavior is highly dependent on the foam quality for a given pressure, the chemistry of polymer and the tube diameter.
Real Real-Time Geosteering
Authors: Phillips Ian C. , Paulk Martin D. , Constant Anne
Published: December 2007

This paper is one of a series published during 2000 to coincide with the launch of an advanced drilling system known as "Anaconda". This drilling system utilises a manufactured carbon fibre composite tube in place of conventional steel drill pipe or coiled tubing. The composite tube incorporates wires built into the wall, making it possible to transmit all the available formation evaluation and drilling data to surface continuously and in real-time.

This paper focuses on the impact of this real-time data availability on the ability to make real-time geosteering decisions. In particular we focus on:

The uncertainty associated with wellbore planning at seismic resolution when compared with the fine resolution required for modelling log responses and planning well bore trajectories. The issues associated with planning well bores in geological space instead of geometrically are also explored. The issues relating to wellbore planning before the well is drilled and in particular the forward modelling of the anticipated log responses. The practical implications of having all the normal formation evaluation data available in real-time whilst drilling a well. These include handling large data volumes and the ability to reach well decisions in significantly shorter time frames. The software systems developed to deliver the ability to update the geophysical and geological interpretation in the time frame required to influence a well path. The technology which makes it possible to steer the drill string effectively in real-time as new data becomes available. The organisational implications for such real-time decision making – such as high-speed reinterpretations under operational time pressures. The business benefits that might derive from this real-time decision making capability – such as reduced numbers of geological sidetracks, ability to terminate a wellbore at the most appropriate time and maximising the productivity of the wellbore.
New Mathematical Techniques for the Optimisation of Oil & Gas Production Systems
Authors: Handley-Schachler Sybille , McKie Calum , Quintero Nylian
Published: December 2007

Recent developments in mathematical techniques have allowed the development of a software package to simulate and optimise the flow of hydrocarbons through oil and gas production and distribution networks of arbitrary connectivity and complexity. It has been successfully applied to a wide variety of operational problems including de-bottlenecking, optimisation of compressor strategies and determining the optimal lift-gas allocation to networks of gas lifted wells.

This paper discusses the innovative mathematical concepts at the heart of the algorithm taking account of both optimisation and modelling aspects. It demonstrates how an integrated approach to optimisation and simulation based on Sequential Linear Programming (SLP) techniques provides the user with substantially enhanced flexibility and reliability compared with traditional nodal analysis type approaches and how these benefits can be realised in concrete practical examples.

Descriptions of the behaviour of physical objects in a production or distribution network is commonly given in the form of measured data sets or discrete performance tables rather than analytical functions. A final focus of this paper is the discussion of how such data sets can be used directly and efficiently in an optimisation context.
In-Situ Generation of Carbon Dioxide: New Way To Increase Oil Recovery
Authors: Gumersky Kh. Kh. , Dzhafarov I. S. , Shakhverdiev A. Kh. , Mamedov Yu. G.
Published: December 2007

Miscible/Immiscible carbon dioxide injection is considered to be as one of most effective technology to improve oil recovery from complicated formations, and hard to recover oil reserves, in particular. Application of this technology can increase ultimate oil recovery by 10-15% and even more1. One of the main advantage of this technology is that it can be applied in a wide range of geological conditions for production both light and heavy oils.

Striking illustration of this technology high efficiency is the fact that the number of active carbon dioxide (CO2) projects worldwide sharply increased during last 20 years, from 30-35 in the beginning of 1980s to almost 100 in 2000, while oil production increased from 25,000 BPD to more than 200,000 BPD during this period 2.

One of the main factor restraining wide application of this technology is its dependence on the natural CO2 sources, transportation of CO2, breakthrough of CO2 to production wells, corrosion of well and field equipment, safety and environmental problems etc. Except Hungary reserves of natural CO2 for field application of this technology are not existed in Europe. This restrains wide implementation of CO2 injection not only in many European countries but also worldwide where this technology could be efficiently applied and significantly improve oil production as well as ultimate oil recovery from depleted oil formations. Carbon dioxide enhanced oil recovery may be the key to recovering huge amount of oil from highly watered, depleted, heterogeneous and other type of so called "hard-to-recover" oil reserves. One of the main advantage of proposed technology is eliminating of CO2 negative impact on the environment and strong control of the process.

New understanding of the nature of miscible displacement process when behavior of CO2 can be explain as a "super critical fluid" opens a unique future of oil displacement using this technology.

Results of R & D as well as new approach in estimation of the efficiency of EOR technology application are described below. Proposed technology of in-situ CO2 generation is based on exothermic chemical reaction between gas forming water solution and low concentrated active acids.
Key to a Successful I.O.R. Project - Application of Horizontal Wells
Authors: Palasthy Gy. , Kristof P. , Benedek L. , Pipicz V.
Published: December 2007

A redevelopment strategy for a hydrocarbon producing reservoir in a complex geological environment is presented in this paper. With the application of the IOR technology, the hydrocarbons, which seemed to be hidden in unreachable parts of the reservoir, became economically extractable, increasing the value of the field.

The thin oil column and the large gas cap are trapped in a low permeability turbidite type sandstone reservoir. The thickness of layers separated by interbedded claymarles is less than 10 meters of each. In the first 15-year production period 12% oil recovery could be reached from the reservoir having 10 mD average permeability. At starting of the production the depletion mechanism was gas cap expansion combined with weak water drive (1975-1985). The initially flowing wells started to produce with artificial gas lift in 1980. Water injection was necessary to maintain the reservoir pressure so this technology was launched in 1985. In the early 90's the reservoir had very poor economics because of the low productivity and injectivity of vertical wells. The forecasted production rates had been keeping to the economic limit.

1993 was a mileage in the production history because the first horizontal well was drilled and completed in the reservoir. By the end of 1999 the number of horizontal oil wells was increased up to 20 inducted by the excellent production results.

During this production period, the continuous reservoir monitoring reflected the problems of different phases of exploitation and what kinds of solution alternatives were induced by the integrated interpretation of the increasing information obtained from production history. This paper answers how the production potential of the reservoir could be doubled in the last seven years and how the forecasted ultimate oil recovery increased to over 40%. Redevelopment of this producing object was reached by the IOR technique. Infilling of the producing well pattern and acceleration of exploitation was the key in this mature reservoir. With 3.6 USD/bbl investments an additional 5.2 million equivalent barrel reserve became proved.
3-D Simulation of the Pressure Drop along Horizontal Wells in a Bounded Reservoir
Authors: Ewing Richard , Ibragimov Akif , Lazarov Raycho
Published: December 2007

The mechanism of pressure drop along the horizontal well and its dependence on hydrodynamic and geometrical parameters of the reservoir and the well is in the focus of our work. A model of single-phase coupled fluid flow in porous media and in a horizontal well is proposed. For solving the problem a hybrid analytical/numerical methods is tested. The developed method can be applied to analytical estimation of the influence of the various parameters (geometry of the reservoir (shape factor), length, and radius of the well, and also well/reservoir conductivity) on Production Index.

In our work we consider the whole area of drainage: the wellbore itself, bottomhole zone of the reservoir and the reservoir periphery as three adjoint media with different conductivity. For gluing different type of fluid flows with different geometry special non-overlapping domain decomposition method is developed.

This method allows to reduce complicated fluid flow in 3-D media to a sequence of "simple" flows in homogenous media with standard shape (such as sphere, cylinder or annular cylinder).
Horizontal Borehole Stability in Naturally Fractured Reservoirs
Authors: Zhang Jincai , Roegiers J. -C.
Published: December 2007

For modeling naturally fractured reservoirs, the dual-porosity poroelastic model is effective and accurate to characterize stresses as well as flow fields. A generalized plane strain and dual-porosity finite element solution has been developed for analyzing horizontal borehole stability. Two kinds of failure criteria (spalling and collapse) were included. Results show that horizontal borehole stability depends strongly on the in situ stress state, the borehole orientation, time, mud pressure and fracture characteristics.
The Challenges of Detecting Gas Entries in Horizontal Well by Using Integrated Production Logging Tool, Case Study
Authors: Al-Ali Hussein Ali , Salamy Salam P. , Haq Shahid A.
Published: December 2007

Recently, horizontal wells in Saudi Arabia have been targeted to improve the recovery efficiency and enhance the reservoir drainage of tight reservoirs. Evaluating the performance of high flow rate horizontal wells with high gas-oil ratio and producing below the bubble point is difficult and often non-unique with conventional production logging measurements. The challenges arise from the following reasons:Gravitational segregation of the oil, water and gas in the well bore,Complicated fluid velocity profiles due to phase separation,Mixed fluid flow regimes,Long and undulating well bores.

For the first time in Saudi Aramco, a high flow rate horizontal well with excessive gas oil ratio has been logged with a coiled tubing conveyed integrated production logging tool. The horizontal well penetrated a heterogeneous carbonate formation with a long transition zone. The objectives of running the integrated production logging tool were the following:Determine the flow profile and estimate the entire contributing length,Locate the gas entry points and determine the gas flow rate, if possible,Evaluate the performance of this integrated production logging tool run for the first time in a Saudi Aramco well producing below the bubble point.

This paper presents a case study of such an application in the difficult environment. The results showed that the entire horizontal section was contributing to the total liquid flow. Gas inflow was difficult to quantify with the exception of the toe of the well, where the gas hold-up was higher than 70% and the gas flow rate was successfully computed. The results are discussed in detail and recommendations are made to improve the interpretation of gas inflow in this environment.
Sand Flowback Control in the Rockport Gas Storage Field in Northern West Virginia
Authors: Myers Roger R. , Gottschling John , Kulkarni Shirish , Shaw J. Stanley , Amick Paul
Published: December 2007

Sand flowback can be a big problem in high rate gas wells. Sand can quickly erode chokes, valves and other surface equipment creating potentially dangerous situations for the gas well operating and pipeline companies.

In 1998 and 1999 several different sand flowback or backflow control methods have been applied in Columbia Gas Transmission Company’s Rockport Storage Field. Deformable particles are the latest innovation for controlling sand flowback. Unlike curable resin coated sands and tacky surface-modification agents, deformable particles differ in that they do not "glue" the sand pack in place, but rather mechanically hold it together by dimpling under stress and physically holding adjacent grains of sand firmly in place. A modest weight percentage of deformable particles can easily lock the sand pack in place, resisting the forces brought to bear by gas and fluid flow within the fracture.

The Oriskany Sandstone in the Rockport Storage Field can be classified as a highly permeable formation capable of a withdrawal rate greater than 40 MMSCFD. Stimulation treatments are routinely pumped to improve the Oriskany’s deliverability back to original levels following workover operations. Prior to running deformable particles for sand flowback control, tacky resin-like chemicals and curable resin coated sand were pumped to alleviate the problem.
Modeling Complex Wells in Detailed Geologies
Authors: Fitzpatrick A. J. , Ponting D. K.
Published: December 2007

Modelling complex multi-branch wells requires a detailed treatment of flow within the well and an accurate description of the flow in the near-well region of the reservoir. Modern geostatistical packages provide high levels of detail – ideally this should be maintained in the near-well region whilst keeping the remainder of the reservoir in a less detailed sense to provide boundary conditions.

We describe a model in which a model of the wellbore flow in terms of pressure, velocity and saturation is solved simultaneously with the reservoir flow equations. Constraints at branches, items of well equipment and well target conditions are included in the formulation, as well as the effects of friction, gravity and fluid acceleration. The resulting couplings are carried through into the main linear solution algorithm for the full system. A simpler well model is used as a predictor for the Newtonian solution of the detailed well model.

Intelligent grid coarsening is used in reservoir regions away from the well of interest. Finer detail near the well may be retained from geological modelling. By running a number of geological realizations costing possible outcomes the benefits and risks involved in various well designs may be assessed. An example is given of the evaluation of cost and risk in the choice of well design.
Reservoir Simulation Model for Fractured and Partially Fractured Reservoirs based on PEBI Grids
Authors: von Pattay Patrick W. , Ganzer Leonhard J.
Published: December 2007

This paper presents the implementation of the dual continuum approach (dual porosity/permeability), into a PEBI grid based, general-purpose reservoir simulator.

Experience shows that not all parts of a reservoir will typically require dual porosity/permeability treatment. Sometimes numerical or other restrictions limit the use of a dual porosity/permeability model. The approach presented in this paper takes these aspects into consideration. It allows creating dual porosity/permeability cells wherever the geological attributes (facies, rock type, fracture intensity) imply to do so. The remaining – unfractured – part of the model will be treated like conventional single porosity areas. Therefore, the number of grid blocks and the CPU time required for the flow simulation are minimized.

Fracture and matrix-fracture transfer properties (including shape-factors) are derived from the geological information and fracture intensity. All of this information and data is stored on a cell by cell basis. Furthermore, the presented method does not restrict any of the superior gridding capabilities of the simulator like local grid refinement, fault or well modeling. The equation system resulting from all grid blocks will be solved fully coupled. The flow simulator is based on a multi-purpose, compositional formulation, and copes with systems ranging from single-phase to multi-phase, multi-component fluid flow.

Several examples illustrate the usefulness and flexibility of this modeling approach for accurate and economic simulation of fractured or partially fractured reservoirs.
New Abandonment Technology New Materials and Placement Techniques
Authors: Englehardt John , Wilson Mary Jane , Woody Fred
Published: December 2007

Recent industry concerns related to the increasing number of idle wells in the United States prompted a search by Chevron Environmental Management Company (EMC) for more reliable and cost effective means of well abandonment technology. This paper presents the results of the search, laboratory research and field pilot testing conducted by EMC and the California Department of Conservation Division of Oil Gas and Geothermal Resources. Additionally, the cost analysis and future areas of research are addressed. The successful implementation of the abandonment techniques discussed in this paper show substantial savings on a per well basis while providing a reduction in future liability.
Mapping Air Quality Plumes from Fossil Energy Sources to Assess the Impacts of Secondary Aerosol Development
Authors: Rappolt Thomas J. , Kerrin Stephen L. , Hochheiser William , Ziman Steven , Reheis Catherine
Published: December 2007

In 1998 the U.S. Department of Energy (DOE) embarked upon a feasibility study to research possible ways to sample air quality plumes from fossil energy plumes, especially in their early stages of transport from the source, to better understand the physical dynamics that contribute to plume buoyancy and secondary aerosol deposition. DOE, along with industry partnerships, including the Western States Petroleum Association (WSPA) and Tracer ES&T, Inc., explored concepts of a sampling platform that could easily and safely access plume dynamics to support more accurate modeling and the assessment of fossil energy impacts to ambient air quality. The requirement was to conduct plume monitoring during low and near zero visibility conditions (i.e. fog) which cannot be accomplished using manned flight vehicles or fast moving fixed winged vehicles. The dynamics of the problem require a flexible, slow flying, highly maneuverable sampling platform, from which detailed plume measurements can be made. Hence a remotely piloted airship, under an instrument guidance and control system, offered the best approach. Such a platform, carrying miniaturized sampling/monitoring payloads, provided detailed data concerning the vertical structure of near-term plumes as well as ambient chemistry. This paper presents the various stages of development of Clean Airship 1, a helium filled remotely piloted mini-blimp, planned for use in The California Regional PM10/PM2.5 Air Quality Study (CRPAQS) to conduct detailed mapping of specific fossil energy air quality plume structure.
Beyond Phase I Environmental Site Assessments: Case Studies of Business Environmental Risk Assessments of Oilfield Acquisitions
Authors: Funston R. S.
Published: December 2007

The American Society of Testing Materials (ASTM) has developed a standard practice (E-1527-00) for conducting Phase I Environmental Site Assessments (Phase I Assessment) associated with the transfer of commercial property. The primary objective of the ASTM standard practice is to identify apparent conditions of environmental concern and conduct adequate due diligence so that the buyer can avail themselves of the "innocent purchaser provision" under CERCLA. There are many potential objectives a buyer of oilfield properties might have in conducting acquisition due diligence beyond CERCLA considerations. Because oilfield properties typically have environmental impairments, the threshold considerations for the buyer typically relate to the management and allocation of risk for current and future liabilities between the buyer and seller.

Historically, oilfield sellers have provided either a full or partial indemnification to the buyer for environmental conditions that existed before the date of sale or have provided a due diligence period after the date of sale for the buyer to conduct additional environmental investigations. Today, typical sales are on "as-is" basis where the seller is willing to entertain adjustments in the purchase price for environmental impairments identified by the buyer in a due diligence period before closing.

An Environmental Business Risk Assessment goes beyond the traditional Phase I Assessment to better meet the business needs of purchasers of oilfield properties in "as-is" deals. The scope of the Environmental Business Risk Assessment is tailored to the risk tolerance of the buyer and the nature of the deal. The Environmental Business Risk Assessment provides information the buyer needs to make informed business decisions about allocation of risk as a part of the negotiation of the Purchase and Sales Agreement.

This paper presents four case studies that illustrate how Business Environmental Risk Assessments were conducted to address unique issues associated with the transfer of four "as- is" oilfield property sales in California.
The Development and Use of Risk Acceptance Criteria for the Construction Phases of the Karsto Development Project in Norway
Authors: Berg F. R.
Published: December 2007

abstract

For the construction phase of onshore plants, standardized acceptance criteria have never been developed within the Statoil Group or the Norwegian landbased industry, although project specific design acceptance criteria was developed prior to the construction of the onshore facilities on the western coast of Norway when developing the huge Troll field some years ago.

This paper focuses on the development process of such criteria for risk acceptance with an emphasis on the construction, commissioning and start-up phases.

The use of risk analyses in plant design, construction and operation is not only a legislatively based requirement in many European countries, i.e. Norway, but also offers a lot of advantageous features to the design process: -Identification of risk and implementation of risk reduction measures in a stage of the project when changes to design and lay out can be implemented relatively easily and with moderate cost compared with implementing the changes after the plant has been built.-Firm and objective decision making on the feasibility of implementing risk reducing measures compared with the rule based approach and above all, decision making based on intuition.-Often a variety of design options can be at hand if verified suitable by risk analyses compared with the rule based approach, which often offers a preset choice of design and construction solutions.

Risk based design and construction allows to a larger degree, tailor made design and construction solutions to be implemented compared with the rule based approach,

In addition, risk analyses can give a substantial contribution to effective implementation of the construction phase and limit the risk both to personnel and material assets.

In order to evaluate risk, risk acceptance criteria is often used and such criteria have been developed for the project, covering: -Risk both to employees and workers being present at site-as well as neighbours in the vicinity of the plant.-Risk to environment.-Risk to material assets.

Two sets of criteria have been established for the evaluation of risk to people, one quantitative set for the strategic assessment of technical risk that can be expressed mathematically and one set to be used when specific work operations or tasks are evaluated.

The later one is being performed by the qualitative use of a risk matrix, where every case can be represented by a frequency of occurrence and a consequence that indicates if the risk is intolerable, tolerable or that can be made tolerable if risk reducing measures are being introduced.

It is firmly believed that the technical risk management system in the this project, including the use of risk acceptance criteria, have been a valuable and decisive success factor in the design and construction of the new facilities.
Establishing Environmental Performance Indicators for the E&P in The Netherlands
Authors: Henriquez Leopoldo R.
Published: December 2007

On June 2, 19951 a voluntary environmental agreement on Implementation of Environmental Policy for the E&P Industry has been signed between the Netherlands’ Government and the Dutch Association of E&P Operators. This so-called E&P

Environmental Covenant, which covers the years 1990 until 2010, comprises quantified environmental targets which should be achieved within a certain period in time. Each individual E&P operator has to provide the Government for a Company Environmental Plan every four years describing the planned reduction measures to achieve those targets. Also yearly the E&P operator has to present a progressreport to the Government. The Government also expects the E&P operator to implement the planned reduction measures through an Environmental Management System based on the ISO 14000 standards. The effectiveness of the implementation is assessed on the basis of environmental performance indicators and by applying benchmarking and a ‘Best In Class’ mechanism.