bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Approach for Matrix Acidizing of Water Injectors in Low-permeability Sandstone Fields
Authors: Wang Xugang , Zou Honglan , Cheng Xingsheng , Li Suzhen , Zhang Boping , Hill A. D. , Zhu D.
Published: December 2007

The goal of this study was to design a cost-effective matrix acidizing treatment to enhance the performance of water injection wells in a low permeability sandstone reservoir in China. The sandstone reservoir in the Western Field in China is ultra-deep, low permeability, and high temperature. The Eastern Field reservoirs are multi-layered and low permeability. Conventional matrix acidizing procedure had been repeatedly applied in the field, but only half of treatments was successful. The effective period of acidizing treatments was short, injectivity of most wells decreasing within three to six months. To develop the optimal procedure for the field, we carried out studies on the acid-rock reaction mechanisms and the secondary damage mechanism during acidizing. We analyzed the spent acid ion concentrations from long-core lab tests, studied the pore structure using, Environmental Scanning Electron Microscopy (ESEM), and the rock compressive strength before and after the acidizing. A new procedure was developed based on the results of lab study. It features injection of organic solvent to remove the organic blockage caused by colloidal asphalt, followed by injection of low concentration organic acid. The wells were put on injection instantly after acid injection to push the spent acid further into the formation without flowback.

46 treatments that have been applied to the injectors in the Western and Eastern oilfield. Matrix acidizing of water injectors in low-permeability sandstone fields succeeded beyond all expectations. The injectivity increased 4 to 15 times, and the effective period has been increased from 6 to 18 months.
Damage Characterization of Deep Bed Filtration from Pressure Measurements
Authors: Bedrikovetsky P. , Tran P. , Van den Broek W. M. G. T , Marchesin D. , Rezende E. , Siqueira A. , Serra A. L. , Shecaira F.
Published: December 2007

Permeability decline occurs during injection of sea or produced water, resulting in well impairment. Solid and liquid particles dispersed in the injected water are trapped by the porous medium and may increase significantly hydraulic resistance to the flow.

We discuss a mathematical model for deep bed filtration containing two empirical parameters – filtration coefficient and formation damage coefficient. These parameters should be determined from laboratory coreflood tests by forcing water with particles to flow through core samples. A routine laboratory method determines the filtration coefficient from expensive and difficult particle concentration measurements of the core effluent; then the formation damage coefficient is determined from inexpensive and simple pressure drop measurements.

An alternative method would be to use solely pressure difference between the core ends. However, we have proved in earlier work that given pressure drop data in seawater coreflood laboratory experiments, solving for the filtration and formation damage coefficients, is an inverse problem that determines only a combination of these two parameters, rather than each of them.

A new method for the simultaneous determination of both coefficients is developed here. The new feature of the method is that it uses pressure data at an intermediate point of the core, supplementing pressure measurements at the core inlet and outlet. The proposed method furnishes unique values for the two empirical coefficients, and the solution is stable with respect to small perturbations of the pressure data.

In the current work the proposed method is used for analysis of laboratory test data on deep bed filtration. The values of filtration and formation damage coefficients are obtained for flow of solid and liquid particle dispersions in a number of different cores. Effects of particle type and porous media wettability on permeability decline are analyzed.
Measurements Of Fractional Wettability Of Oil Fields' Rocks By The Nuclear Magnetic Relaxation Method
Authors: Brown Robert J.S. , Fatt Irving
Published: December 2007

Introduction

The wettability of reservoir rocks is recognized as one of the major factors that determines their multiphase flow properties. Multiphase flow properties in turn govern reservoir performance. For this reason, the reservoir engineer is vitally interested in the wettability of reservoir rock. The production research scientist is interested in wettability because the solution of the problem of improving water flood recovery by use of surface-active additives may hinge on a detailed understanding of the wettability of reservoir rock.

Early workers believed that all reservoir rocks were preferentially water wet. Continued study soon uncovered certain rocks which had flow properties that indicated that they were preferentially oil wet. Recent studies show that there is a spectrum of wettability. Some reservoir rocks have multiphase flow properties which indicate that they have an intermediate wettability. The differences in recovery observed among different reservoirs may, in part, be the result of small differences in wettability.

Differences in wettability among reservoir rocks may be the result of differences in the friction of the total surface area that is preferentially oil wet and preferentially water wet. Nuclear magnetic relaxation measurements provide a method for determining the fraction of preferentially oil wet and preferentially water wet area in porous media. Measurements to be reported here were made on water saturated unconsolidated sand packs which were mixtures of preferentially oil wet and preferentially water wet sands. The resulting data show definitely that the fraction of each wettability in the sand pack can be determined by this nondestructive method of measurement.
Underbalanced Drilling–Perceptions and Realities of Today's Technology in Offshore Applications
Authors: Hannegan D. , Divine R.
Published: December 2007

The Oil and Gas Industry drills thousands of wells globally each year, but what makes a well "successful" depends to a large extent on the perspective of the assessor. To the drilling engineer, a successful well is one that is safely drilled to target depth on time and under budget. The production engineer would add the need for there to be no, or minimum, formation damage and that the well achieve its maximum production potential. Unfortunately, these two aspects are rarely obtained within the same wellbore, due to the problems associated with the managing Equivalent Circulating Density (ECD) and the resulting fluid invasion, while drilling in the reservoir.

The management of ECD is "traditionally" achieved by drilling with mud, suitably weighted, to drill within a pressure margin until a casing point is mandated. This method has both benefits and detriments. The mud column provides primary well control in a conventionally drilled well, while the BOP equipment is secondary well control. This is the standard approach in the drilling industry, as mandated by regulatory agencies. However, it prevents approximately 20-30% of the known world's offshore oil and gas resources from being developed, due to excessive ECD when drilling. The tools and technology associated with underbalanced drilling (UBD) have added a beneficial dimension to ECD management. UBD tools and techniques are key to several emerging offshore technologies such as: drilling with subsea and surface BOP stacks with pressurized mud return systems, the concept of Dual Gradient Drilling, and using subsea rotating diverter control heads to control shallow water flows when drilling riserless. Underbalance drilling moves the primary well control from the mud column's hydrostatic pressure to the surface equipment where it is more easily managed and predictable.

This paper reviews key situations that are typically encountered when drilling offshore and make comparisons between "conventional" methods and UBD technology. The latest technology is reviewed to illustrate how drilling UB offshore can be safe and efficient to achieve a "successful" well from multiple perspectives. Such capability is now viewed by most majors as a requirement in many offshore situations to deal with depleted zones/reservoirs relative to water depth, narrow margins between fracture gradient and pore pressure, and for dealing with abnormally pressured aquifers (shallow water flow hazards). To date, the UBD applications used offshore have achieved an ECD nearer to reservoir pressure, thus minimizing skin damage from drilling fluid invasion.
Diagnostic Fracture Injection Test in Coals to Determine Pore Pressure and Permeability
Authors: Ramurthy Muthukumarappan , Marjerisson Douglas M. , Daves Scott B.
Published: December 2007

Permeability and pore pressure are critical parameters in the evaluation of a coalbed methane (CBM) project. Coal permeability is particularly problematic, as it is highly stress dependent and estimates made from cores generally do not adequately reflect in situ reservoir conditions. Pressure buildup, injection falloff and more often slug tests have been used to determine in situ permeability in coal. However, buildup tests are costly, time consuming, and cannot be applied effectively in underpressured reservoirs; slug tests require an accurate estimate of wellbore storage effects. Similar to buildup tests, injection falloff tests are very time consuming and costly because of the longer shut-in times. Also, if fracture pressure is exceeded during an injection-falloff test, conventional analysis can give erroneous results. This paper presents a more effective method for determining pore pressure and permeability in coals using a diagnostic fracture injection testing technique.

A diagnostic fracture injection test (DFIT) is a small-volume, cost-effective, and short-duration test that has been used successfully in tight gas sands in the Piceance and other basins. The test consists of (1) a G-function derivative analysis to identify the leakoff mechanism and closure, (2) a calibrated before-closure analysis using modified Mayerhofer method to determine the permeability, and (3) an after-closure analysis to estimate pore pressure and permeability. The uniqueness in applying this test in coals is that both the before- and after-closure analysis can be utilized where pseudo-radial flow is not dependent upon the fracture half-length. The technique works because the permeability in coals is high enough that after-closure pseudo-linear and pseudo-radial flows are normally observed with an extended shut-in. Once pseudo-radial flow is observed, estimating pore pressure and transmissibility becomes straightforward and provides calibration for the before-closure analysis.

Hundreds of diagnostic fracture injection tests have been conducted in all the CBM basins in the rockies and in Canada with remarkably consistent results. Examples are provided from San Juan basin and Canadian coals where diagnostic injection tests have been applied successfully for various operators. DFIT's have been applied successfully in other CBM basins like Sand Wash, Greater Green River, Piceance, and (western) Powder River basin.
Recovery Methods for Heavy Oil in Ultra-Shallow Reservoirs
Authors: Dunn-Norman S. , Gupta A. , Summers D. A. , Koederitz L. F. , Numbere D. T.
Published: December 2007

This paper discusses processes for sustainable recovery of heavy oil from ultra-shallow reservoirs, using low cost, innovative horizontal drilling and completion methods, combined with regional reservoir mapping and reservoir characterization.

Heavy oil exists in the shallow Pennsylvanian sands in Southwestern Missouri and Southeastern Kansas. These sands occur over an area of about 8,000 sq. miles that extends for 250 miles along the Kansas-Missouri border. Reserves are significant, with approximately 2 billion barrels of oil in Missouri alone1.

Recovery of the heavy oil in these shallow reservoirs has proven difficult. While the oil does flow into an open wellbore under natural conditions, flow rates are low due to the nature of the oil (18° API, 1000 cp.) and the low reservoir pressure due to shallow reservoir depth (< 200 ft or 61 m).

Historically, industry has examined or attempted a number of development schemes including steam injection, CO2 flooding, in-situ combustion, direct electrical heating, stimulation with borehole explosives, and the application of solvents in conjunction with subsurface explosives. The most recent, and perhaps most successful development scheme included cyclic steam injection enhanced with flue gas. This project operated successfully for a number of years and resulted in average flow rates of 12 bopd.

Economic recovery of the ultra-shallow heavy reserves requires a process that is both inexpensive and easily applied. Novel, water-jet horizontal drilling and horizontal fracturing coupled with microbial enhanced oil recovery provide such a low cost method of recovery. This paper details these completion processes, their sustainability, and their potential for regional application. The paper also discusses the application of geochemical and/or shallow geophysical methods for regional mapping of the heavy oil sands, and the reservoir characterization methods for the shallow reservoirs.
Effective Stimulation Proved to be the Key to Economic Horizontal Completions in Low Permeability Carbonate Reservoir
Authors: Willett Ronald M. , Borgen Ken L. , McDaniel B. W.
Published: December 2007

When an operator is planning to drill a horizontal completion in a lower-permeability carbonate or sandstone reservoir, one of the prime well-design considerations is cost containment. Unfortunately, many operators use decision-making processes that are inappropriately weighted toward cost reduction and insufficiently or incompletely weighted toward incorporating completion processes that will ensure adequate producing rates. As a result, the ultimate hydrocarbon recoveries that were used in the economic justification of the program may not be achieved.

This paper presents a case study of a multi-year horizontal completion project in west Texas that was very successful in exposing the "false economy" of not cementing casing in horizontal wells drilled in low-permeability reservoirs. Increasing initial well costs about 20 to 25% resulted in a 3-to 10-fold increase in economic returns. This project included wells drilled in the heart of the play, in one of the flank areas, and also in an "edge" portion of the field, with comparisons to openhole completions in each area. The project offers several guidelines that should be followed by almost any global application of horizontal completions in lower-permeability reservoirs.
Northstar Drilling-Delivering the First Arctic Offshore Development
Authors: Krieger Andrew G. , Kidd Gavin N. , Cocking David A.
Published: December 2007

Drilling oil wells on the North Slope of Alaska is not a new endeavor. Thousands of wells have been drilled over the past two decades in order to fill the Trans Alaska Pipeline. The majority of these wells have been drilled from a number of large drilling pads connected via a road network. Some of the newer developments have been drilled from remote pads accessible by fixed wing aircraft and ice road during the winter. So what is it that makes the Northstar Development stand out among all other drilling operations on the North Slope? It is the first Arctic Offshore Development that is not accessible by road for most of the year and does not have fixed wing air support. The implications of limited access to a 400’ by 400’ island are enormous. Successful completion of the first drilling season at Northstar is a significant milestone marked by detailed design and execution as well as pure determination. Many of the challenges were anticipated and accounted for while many others were not. The first Arctic Offshore Development delivered its first barrels of oil as per schedule on 2nd November 2001. Now comes the next challenge-drilling more for less to improve the profitability of this unique Alaskan project.
Evaluation of Hydraulic Fracturing and Re-Entries in the Hassi-Messaoud Field, Algeria
Authors: Rahmouni Noureddine , Tiab Djebbar , Azzoughen Athmane , Mazouzi Amine , Escobar Freddy H. , Zhu Tao
Published: December 2007

Since 1990, two emerging techniques, hydraulic fracturing and re-entry techniques, have been applied in HMD Field, Algeria, to increase oil production. This paper analizes the production data for more than 17 re-entries and 60 fractured wells. The results indicate that oil production from 13 out of 17 re-entries declined rapidly to below the original level within a year, and 31 out of 60 fractured wells are not profitable. To analyze the well performance from field data, a 3D simulator was used to evaluate both hydraulic fracturing wells and re-entries. Several scenarios were built for each technique. The effect of fracture length, fracture width, fracture height, re-entry length, pay zone, and oil price on technical and economical success was analyzed. Risk analysis was used to take into account of practical, economical, and other unexpected factors. The results show that fractured wells are profitable but not for re-entry wells.
New Methods for Sand Cleanout in Deviated Wellbores Using Small Diameter Coiled Tubing
Authors: Engel S. P. , Rae Phil
Published: December 2007

The use of coiled tubing to remove sand from well bores was one of its earliest applications and continues to be an important service today. In fact, sand clean out operations in the Asia Pacific Region still represent some 30% of CT service activity. However, the trend towards more complex well trajectories and reduced topside facilities offshore can impose operational constraints on this essential service.

This paper describes a method of transporting sand out of low-pressure wells, of any angle, using small diameter coiled tubing. It describes the philosophy employed as well as the technical and economic rationale behind that approach. A case study reviews some unique rheological properties of sand suspension fluids and field performance characteristics.

The industry has developed a number of alternative solutions to sand removal, including concentric pipe, wiper trips, jetting techniques and the deployment of large diameter pipe. With the commercial constraints of the service business, depleting reservoir pressures and increasing numbers of high angle wells, the method described supplements the current range of clean out solutions with its elegance, simplicity and logistical merits. This technique involves particle entertainment at the BHA to fluidize the sand and subsequent displacement from the well at low velocities. The main benefit of the system is the avoidance of the need for large diameter, heavy and expensive hardware and the ability to operate in areas where weight restrictions exclude the use of larger equipment.
Assessment of Risk and Size Dependencies in a Geologic Play with Multiple Zones and Multiple Prospects
Authors: Wang B. , Kokolis G. P.
Published: December 2007

This paper describes a precise method to assess twodimensional, partially dependent risks for geologic plays that contain both multiple zones and multiple prospects. Prior methods have considered only one-dimensional solutions; that is to say, plays with risk dependencies between either multiple zones or multiple prospects, but not both.

Decision-tree methods are used with the input of assumed vertical and horizontal dependencies for multiple geologic controls (such as charge, reservoir, structure, and seal), along with the assumed initial geologic control risks, and the assumed chance of drilling for each prospect. Throughout the calculation process, the weighted-average dependent risks are maintained as identical to the initially assumed risks. This rule of "risk conservation" must be honored to avoid unintentionally over or under estimating the evolving risks which result as wells are drilled and prospects and zones succeed or fail.

This paper details the logic and calculation procedure that we use to estimate the overall chance of success and potential resource size for a play with two-dimensional risk dependency. A spreadsheet program can be used to implement the calculations. A complete risk evaluation of a 3-zone, 6-prospect lease block is demonstrated.

We also investigate the impact of resource size dependency in play assessment. In the past, size dependency was generally ignored to simplify calculations. Size dependency will not change the overall geologic risk or the mean geologic resource estimate of a play. It can; however, alter the overall resource distribution (e.g. variance and resulting P10, P50, P90) and the commercial (or truncated) risk and mean resource estimates. Consideration of size dependency is important for plays with highly dependent risk factors, but not important for plays with independent risks.
Multiwell Interference Test in the Colville River Field, Alaska
Authors: Erwin Mike D. , Sanders L. Allen , Redman R. Scott
Published: December 2007

This paper documents a unique pressure transient test conducted prior to start-up of the largest onshore oil field discovery in North America in the past decade. In March 2000, a multi-well interference test was initiated to enhance understanding of field scale reservoir continuity, permeability, fracturing and injectivity. Testing began eight months prior to ‘first oil’ involving eleven development wells. This inventory of completed idle development wells prior to field start-up provided a unique opportunity to pulse test a ‘silent’ reservoir.
Determining Reservoir Stratigraphic Continuity via Well Testing in Deepwater Gulf of Mexico, Fuji Prospect
Authors: Haddad S. , Cribbs M.
Published: December 2007

The Fuji Prospect is located in the Green Canyon Blocks 505 and 506 approximately 180 miles south-southwest of New Orleans in a water depth of 4,280 ft. The discovery well, Fuji Well #1 (Green Canyon 506 Well #1) encountered 182 ft of oil pay in four Lower Pliocene age sandstones and was temporarily abandoned in 1995. The second well, Fuji Well 2 (Green Canyon 505 Well #1) was drilled in 1997. The well encountered 214 ft of oil pay, in sands equivalent to the pay sands and some wet sands seen in the discovery well.

Well tests were performed on two pay sands. Both tests had low productivity rates of less than 5000 BOPD and recorded pressure depletion. The 1st test indicated a small compartment. The 2nd test was inconclusive and could be explained by either a small compartment with high permeability or a larger compartment with very low permeability.

The Fuji Well 3 (Green Canyon 506 Well No. 2) was drilled next, in a structural position between Fuji Wells 1 and 2 in order to confirm stratigraphic continuity of the reservoirs. It penetrated 227 ft total of oil pay sands and 123 ft of oil pay in the shallower interval. The main field pay sand was the Magenta Sand, which was tested in Fuji Well 3 at a rate of 7,192 BOPD. The Magenta Sand in Fuji Well #3, however, showed pressure depletion during the test. Fuji Well #3 was temporarily abandoned in March 1998.

The Fuji #2 and Fuji #3 well test design and results will be presented. Pressure transient interpretation challenges and conclusions will be discussed. This work will also demonstrate the impact of well testing on determining stratigraphic continuity and reserves calculations.
Identification of Steam Breakthrough Intervals Using DTS Technology
Authors: Johnson D. O. , Sugianto R. , Mock P. H.
Published: December 2007

With the development of several novel methods for installing optical fibers in oil and gas wells for the purpose of "Distributed Temperature Sensing" (DTS), the search is on for gaining the considerable value offered from this remarkable technology. An Extremely cost effective and accurate method of determining steam breakthrough in producing wells has been developed which takes advantage of the power of DTS technology.
Optimization of a Horizontal Flow Electrostatic Coalescer in Offshore Gulf of Mexico Service
Authors: Heatherly M. W. , Buchanan V. P. , Rawlins C. H.
Published: December 2007

An advanced design horizontal flow oil coalescer was installed on the Marathon-operated Ewing Bank 873-A (EW-873A) platform in early 1998. The coalescer's design has enabled it to significantly exceed design capacity while simplifying operations. Design features that aid in performance include: horizontal flow to minimize water carry-over with the bulk oil phase, a cyclonic inlet device to smooth the pipe-to-vessel transition and degas oil at inlet conditions, externally adjustable louvers to distribute oil flow evenly across the vessel, multiple externally adjustable electrostatic grids to vary field density and allow improved coalescence, and directed-flow matrix packing in the oil layer to enhance the removal of the coalesced water droplets created by the electrostatic field. Operation and maintenance improvements include: internal sampling points to quickly assess performance along the length of the coalescer, externally replaceable grid entrance bushings, and an interface draw-off line to remove chemical/solids laden pads.

This unit was installed as part of a platform upgrade and operates parallel to a vertical upflow coalescer. The existing upflow coalescer is frequently unable to achieve 1.0 % BS&W in oil effluent at lower than design rates, while the horizontal flow electrostatic coalescer consistently provides <0.4% BS&W at 120% design capacity (61,000 BOPD versus 50,000 BOPD). This paper will detail horizontal flow coalescer design, with an emphasis on internal components, and provide highlights from its four-year operating history in a side-byside comparison to a conventional upflow coalescer.
Planning and Execution of Long Horizontal Gravel Packs in Extended Reach Wells
Authors: Corbett Gary , Winton Suzanne
Published: December 2007

Horizontal openhole gravel packs provide excellent sand control, high productivity and sustained well life. This paper describes the application of openhole horizontal gravel packing to extended reach wells in a North Sea field. Openhole horizontal gravel packed sections in this field range from 1,200 ft to almost 7,000 ft in length. The key to successfully gravel packing these ultra-long horizontal wells is proper planning and field execution. The initial planning process requires identification of the risk factors associated with horizontal gravel packing. These risk factors are discussed in the paper, as well as techniques available to reduce risk. In addition, this paper describes the extensive well planning process required to design and execute long horizontal gravel packs. Issues such as well path selection, workstring selection, drill-in fluids, well displacement, service tool configurations, rig-site logistics and contingency planning are discussed in detail. Finally, a summary of the gravel packing results achieved to date in the subject North Sea field is presented.
Water Control in Oil Wells With Downhole Oil-Free Water Drainage and Disposal
Authors: Inikori Solomon O. , Wojtanowicz Andrew K. , Siddiqi Sarmad S.
Published: December 2007

In bottom water drive oil reservoirs, the use of dual-completed wells with water drainage-dubbed: Downhole Water Sink (DWS) technology - has proved to control water coning, increase oil production rate and total recovery factor. Also, in field trials, the technology demonstrated sustainable production of oil-free drainage water. The ability to produce oil-free water makes DWS extremely attractive in offshore operations as no water processing is needed prior to overboard discharge. In land operations, oil-free water may be injected into the same well below the drainage completion or lifted to the surface and disposed into injection wells without processing.

Field tests and our studies have also showed that sustainable drainage of oil-free water becomes somewhat difficult as the two completions (top and bottom) may receive co-mingled inflows of the two fluids. The phenomenon indicates the existence of transition zone (with mobile oil and water) much larger than that explained by the capillary pressure effect. This paper presents the results of a study - using numerical simulator and a pie-shaped physical model-aimed at understanding the change of transition zone around producing wells with and without DWS.

The results show that, in conventional wells with water coning, the transition zone is small and constant away from the well but enlarges towards the wellbore. This transition zone enlargement effect occurs in conventional wells due to diffusion resulting from pressure distribution around the well. For DWS wells, however, the effect is not only more pronounced but it also alters the IPW plots – a basic tool for design. There is a commingled inflow envelope in addition to the envelope of segregated inflow.

Based on the above understanding, the paper shows how to design operational limits for DWS wells to maximize oil production from the top completion and maintain oil-free water drainage from the bottom completion.
The Development and Testing of a Garaged Open Hole Logging System for High Angle Wells and Bad Hole Conditions
Authors: Elkington P. A. S. , Spencer M. C. , Spratt D. L.
Published: December 2007

A mechanism for conveying logging tools inside drill pipe has been developed that reduces the risk and cost of acquiring open hole formation evaluation data in high angle wells and bad hole conditions. The measurement string is garaged inside drill pipe where it is protected while running-in, being released into open hole close to final depth. Wireline tools are used for data quality reasons, but the wireline has been eliminated, giving time, well access and well control advantages relative to wireline pipe conveyed logging. Over shallow, long horizontal intervals the time savings are substantial because wireline re-latching is eliminated, and pipe is run-in at tripping speed. The ability to circulate over and around the tools means that logging and hole cleaning trips can be combined to give further time reductions. Cost and data quality advantages have been demonstrated relative to logging-while-drilling in wells where real-time formation evaluation data is not used to guide the drilling process.

A 1.4-Km test loop constructed during the development phase proved the tool deployment sequence can be controlled and monitored using mud pressure. It enabled the design to be refined before being run in real well environments, and resulted in the development of novel payload delivery seals - a key component in the system.

Using the new method, formation evaluation data has been acquired in horizontal wells that would not have been logged previously for reasons of accessibility and/or cost. Knowledge gained from the interpretation of these data sets has influenced the installation of completions in new wellbores, and guided remedial action in others.
Developing New Fields Using Probabilistic Reservoir Forecasting
Authors: Kabir C. S. , Chawathé A. , Jenkins S. D. , Olayomi A. J. , Aigbe C. , Faparusi D. B.
Published: December 2007

Limited and uncertain geologic and engineering data at the onset of any new field development are the bane of reservoir characterization and simulation. The problem stems from the uncertainty in various model-input variables, such as reservoir connectivity, fluid viscosity, and endpoint saturations, to name a few. Given this scenario, an ad-hoc, one-factor-at-a-time approach to earth and flow-simulation modeling cannot possibly yield unbiased information for making objective business decisions.

This study presents three field cases where both engineering and earth model variables were varied in a systematic way to assess reservoir performance using the Experimental Design (ED) approach.

Results of the field cases show that well requirements, both producers and injectors, turned out to be fewer than those thought initially. Equally important, one case study showed that laboratory measurements could minimize uncertainty surrounding oil viscosity and endpoint saturations. At the same time, we learned the preferred horizontal well orientation was marginally superior to vertical wells, in light of high reservoir anisotropy. In another case, stratigraphy, gas-oil contact, and aquifer strength became the primary variables for the full-factorial design, after the initial screening. Here, we proved that the project could proceed because it met the minimum reserves criterion. Perhaps most important, all studies showed how to obtain unbiased information in far fewer flow-simulation runs than one would do using an ad-hoc approach.
Thermal Behavior During Restart of Ultradeepwater Flowlines
Authors: Golczynski T. S. , Niesen V. G.
Published: December 2007

For subsea tiebacks in ultradeepwater, restarting from shut-in conditions can pose significant flow assurance issues. For both planned and unplanned shutdowns, live fluids from the wellbore will come into contact with a cold flowline and can form hydrates during restart since the conditions at the mudline are often well within the hydrate formation region. As the water depth increases, the potential for even higher shut-in pressures exists, exacerbating the probability of hydrate formation.

The achievable restart flowrates are directly related to the available inhibitor rates. Ultradeepwater systems often require high hydrate inhibitor (i.e. methanol) dosage rates to protect the flowline from hydrate formation. In general, the temperature warm-up trend is exponential and is a function of the amount of energy input into the system. If the restart flowrate is too low, limited by inhibitor availability, the temperature may slowly approach a condition at which the system is free from hydrate formation and ultimately require a significant inhibitor volume. For these low restart flowrates, the time to reach conditions above the hydrate formation region can be very significant or the flowline may never warm up above hydrate conditions. At high restart flowrates, the flowline warms up quickly, but the inhibitor delivery rates are high, often significantly higher than those required for a similar development in shallow water. There is a trade-off between inhibitor deliverability (line size) and consumption (storage) that must be accounted for at the design stage of a project when considering how to restart the system.

Operational procedures such as preheating the flowline with dead (de-gassed/de-watered) crude oil to warm up the pipe walls before restarting the wells have been suggested as a means of expediting the overall flowline warm-up. Preheating the pipe walls maintains the thermal energy in the production fluid and reduces temperature losses associated with the fluid warming up the pipe walls. The effectiveness of this technique, while potentially reducing the warm-up time, may again be limited by the allowable restart flowrates.
Wellbore Heating To Prevent Liquid Loading
Authors: Pigott Mikell Jason , Parker Mike Henry , Mazzanti Daryl Vincente , Dalrymple Larry Verl , Cox Don Crafton , Coyle Robert Aden
Published: December 2007

The Pettit formation in Carthage Field is predominately a gas reservoir. At reservoir pressure and temperature, no free liquids are produced. However, water and condensate will drop out of the gas stream as the gas cools on the path to the surface. When the production rate declines below the critical velocity these fluids can accumulate and cause the well to load up and eventually cease flowing.

Heating the wellbore to reservoir conditions is a new method of eliminating fluid condensation in the wellbore. This paper discusses the first successful application of wellbore heating to prevent fluid condensation and eliminate liquid loading. This application is in the Carthage Field.
Managing Exploration Performance: A Case Study For The Use Of The Internet To Enable Real Time Portfolio Management
Authors: Hewitt Bill , Wilson Hamish , Roberts Spencer J. , Fullerton Daryl
Published: December 2007

This paper describes how BP designed and set up a web-based system to manage the performance of their Near Field Exploration programme. The programme is characterised by a dynamic high volume of activity, as compared with more traditional exploration. Therefore capital must be managed and moved between business units throughout the year to continuously maximise production delivery for a given level of exploration spend.

The traditional methods of managing exploration, with annual capital allocation and ‘in-year’ quality assurance were not appropriate. The Near Field Group evolved a process based around quarterly meetings to review performance and agree the next quarter's activity. In effect, the group's goal was to manage the near field portfolio on a real time basis to continuously optimise performance. To achieve this goal accurate data on the individual investment options became an essential requirement.

The Internet provides a technological solution to support this process. BP, with external assistance, built a web-based system for collecting and managing individual investment options. A ‘Rapid Build’ approach using ColdFusion and other Internet technologies was used to develop and deploy a ‘live’ system within four months. The system is database driven utilising a web-interface to gather and display data through a series of forms and summary cards. It also offers the ability to display real time data through a series of customisable reports and dynamically generated graphs. The application resides on BP's intranet and forms a networking tool for all the business units in the Near Field Group. The primary function of the system is a commercial prospect database, which is regularly updated through the web at each local office. The database contains details of current and future prospects and also manages data on completed projects (both success and failure) in order to monitor their production delivery through time. This allows continual refinement of the groups technical prediction accuracy.

The system has been implemented for over two years and the ability to dynamically manage a portfolio on a real time basis has proved its worth; the Near Field Exploration programme is a great success. Many other features to facilitate collaboration have been incorporated. A significant benefit is the ability to collectively make investment decisions without meeting face to face. In today's business climate the ability to make faster more informed decisions with confidence is essential.
An Integrated Approach To Optimizing a Large Asset
Authors: El-Banbi Ahmed H. , Fathy Khaled , Morsy Samir Y. , Aly Ahmed M. , Alam Alaa , Fattah Mohamed A.
Published: December 2007

A major integrated study was performed to optimize the development of a complex field and to find opportunities to increase oil production. The field is composed of eight stacked reservoirs. The field was developed with more than 160 wells and has been producing since 1960. A pilot gas injection project was installed in the early 1990's. Despite the large number of wells and long production history, only 10% of the OOIP was recovered to date. An integrated approach was used to construct a dynamic model for the field and couple it to economical calculations. The model was used to optimize the performance of the field, increase recovery factor, and accelerate production. Unique to this paper is the procedure of history matching large amounts of data and long history. A relatively large model was constructed and then was broken down to seven models. The history match was attempted for each model separately. The seven parts of the field were then combined and the history match was refined. This history matching procedure resulted in significant time savings in the study and allowed the study team to dedicate most of their time to field optimization and to understanding the reservoir behavior.
Exceptional Proppant Flowback Control for the Most Extreme Well Environments: The Shape of Things to Come
Authors: Stephenson Christopher , Ward Brian , Taylor David Milton , Brannon Harold , Rickards A.
Published: December 2007

Proppant flowback within deep hot wells and/or highly productive wells is a major problem in the oil and gas industry. Under these extreme conditions, many of the current products and processes to control flowback often fail. As such, improved or alternative technology and procedures are constantly being sought. One such technology is the development of deformable proppants.

Material and structural improvement to a deformable proppant has allowed laboratory test conditions to be extended to higher temperature, closure stress and flowrate. As a result of this fine tuning, exceptional proppant flowback control has been obtained. Testing of this new deformable proppant, blended with typical fracturing proppant, has shown 50 fold increases in flowrate and 100 fold increases in pressure drop are attainable without pack failure, while still maintaining fracture conductivity.

Furthermore, this deformable proppant has been applied in wells where current technology would either fail or have serious drawbacks. In two primarily gas producing reservoirs, the addition of this deformable proppant to proppant packs placed during fracturing treatments, has been observed to very effectively control proppant flowback under conditions of high bottom hole temperature, high fracture closure stress and high production regimes. In order to facilitate field application, new addition and monitoring procedures were developed to accomplish these successful fracturing operations. The developmental testing, successful application and well performance all indicates significant improvement in proppant pack integrity.
An Improved Placement Technique for Resin-Coated Gravel in Through-Tubing Gravel Packing
Authors: Berg Erik , Haugum Ola , Reinertsen Trond , Harestad Kristian
Published: December 2007

Through tubing gravel packing in wells with ID restrictions inside the production tubing is a challenge related to installation of down-hole equipment and placement of gravel in perforations and behind casing.

In the North Sea conventional gravel packing has been the preferred method with regards to remedial sand control, but in wells with ID restrictions this can lead to a reduced accessibility and flow impairment in the producing well. Use of resin coated gravel without pre-installed screens is also utilised as an alternative method but has been limited to short perforation intervals due to insufficient placement techniques.

In 1999 a high rate oil producing well at the Snorre field in the North Sea was gravel packed with 16/30 mesh resin coated proppants utilising a new tool for improved placement of proppants behind the casing and inside the perforations.

The well was completed with a 7" liner, cemented and perforated, and a 5.5" production tubing. The smallest ID inside the production tubing was a "no go nipple" of 3,75". An interval of 34,5 m containing three perforated zones of total 12,5 m was gravel packed in one operation. The placement tool which consists of 7 glasfiber tubes designed as an internal shunt tube system, allows gravel slurry to be pumped past possible sand bridges forming in long intervals. The tool was split in three lengths of approximately 14 m each and placed in the well on wireline. The gravel pack operation was performed through coil tubing in squeeze mode with pre- heated carrier-fluid to improve the curing of the resin. A total of 10 ton. proppants was pumped during the operation and 7,6 ton. of proppant was placed behind the casing and in the perforations, giving a gravel pack efficiency of 3.9 ft3/ft of perforations. After curing, excess proppants and the placement tool was milled out with coil tubing.
Capillary Shockwave Front Blind Imaging of Reservoir Limits: A Case Study
Authors: Goldsberry Fred L. , Anderegg Kevin C.
Published: December 2007

Reservoir boundary information is gleaned from a steady-flowrate-drawdown test and/or a subsequent buildup following the steady flow period. Singularities are observed to be present in virtually all transient pressure data that can provide direct information about the limits around a well. Multiple limits can be detected discretely and described by distance from the well and angular shape at the point of contact. The input information required is pressure data acquired while flowing on a fixed choke, petrophysical properties from cores and electric logs, and fluid production rates and compositions during the flow period.(2)

Reservoir limits can be assembled into an energy equivalent image based upon cone of influence energy growth behind a bounding initiating capillary pressure shockwave front. The resulting image can then be compared with a seismic data based map or a geologic map. Volume integrals for gas inplace can provide an early physical measurement for reserve accounting purposes.(4,5,6,8)

A variety of boundary contact shapes were assembled into a "blind" energy map that was later confirmed by seismic imaging. A direct overlay comparison of the "blind" energy image and a 3D seismic map is presented. The limit information will be compared with the seismic image to confirm it point by point.

This new transient pressure analysis method is based upon a real capillary network growing from the well bore. Flow into the well bore is restricted to radial flow and confined to the real capillary flow paths by initial capillary pressure.(2) The cone of influence is bounded by an associated capillary shockwave front that restricts its growth. The bounding initiating capillary pressure shockwave front is the physical phenomenon that exists at the radius of investigation(1,7,10) The capillary networks give rise to secondary pressure singularities when a boundary is encountered. The method extends traditional analysis to the realm of wave mechanics(8,9,11) and allows direct data processing. The solution is based upon an energy model that solves for boundary geometry directly from flow and buildup data without the process of traditional iterative history matching. The boundary contacts can then be assembled into an image of the reservoir based upon relative disposition of individual limit contact.
Management of Completion Systems Utilizing State-of-the-Art Technologies
Authors: Thompson Joseph E. , DeVine Carolyn S. , Garner J. Jay , Wood William D. , Eller J. Gary
Published: December 2007

Management of a robust completion approach, utilizing state-of-the-art technologies, has been successfully used to stimulate multiple pay tight gas sand intervals in an environmentally sensitive area near Kenai, Alaska. Management of several unique completion techniques has demonstrated exceptional effectiveness.

Previous stimulation attempts were not successful in developing the Beluga sand resource to an economic level; therefore, a comprehensive study of all processes by reservoir, drilling, completion, and service company engineers was initiated to determine the best techniques to improve recovery and financial delivery.

Engineering and laboratory studies were conducted to develop a complete understanding of the Beluga sandstone reservoir composition; mechanical and chemical properties were analyzed after which an extensive project was undertaken to develop a fit-for-purpose stimulation fluid. For the well completions, a novel Casing Conveyed Perforating System (CCPS), which has revolutionized multi-zone fracturing operations, was utilized. The CCPS facilitates pinpoint stimulation of multiple pay intervals in a relatively short period of time and also improves stimulation quality, hydrocarbon recovery and life-of-well economics.

Recycling of the hydrocarbon-based stimulation fluid provided an additional project enhancement. The recycling process provides a stimulation fluid with excellent rheological properties. Management of the fluid recycling process also reduces the total volume of base hydrocarbon transported and stored in environmentally sensitive areas like those in Alaska. Recycling also minimizes the equipment footprint and minimizes overall completion cost. Wells completed using these unique reservoir evaluations, CCPS, and stimulation fluid recycling techniques have been considered technical and economic successes.