bluuebunny/crossref_metadata_2025 huggingface dataset:
START: What it Means to us All
Authors: Nystrom Mark F. , Senior Lewis M.
Published: December 2007

And so "building" a Safety Management System (SMS) for the organization will focus peoples’ energies on safe work practices, right? OK then - combine effective management of the system and the work place becomes safe, right? Getting closer granted, but why do incidents continue to happen despite elaborate and sophisticated systems in place to keep everyone safe and out of harms way? Perhaps there needs to be a refocus on people - the actual drivers of the system. Alas, close attention to how people behave, their actions, and inaction. Attention in the form of Observing! It seems that too many systems today are driving the actions of people instead of peoples’ action determining system direction. START is a process which produces positive results in peoples’ behavior through observations and positive feedback. It changes an organization's culture by changing peoples’ hearts.
Managing Offshore Process Plant Integrity
Authors: Edmondson J. N. , Findlay K.
Published: December 2007

Loss of hydrocarbon containment accidents present the greatest threat to the offshore workforce. Hence it is imperative that the highest standards are maintained with respect to the design and operation of offshore process plant. The Offshore Safety Division (OSD) of the UK Health and Safety Executive, the British health and safety regulatory body, has undertaken a series of theme audits examining the management of offshore hydrocarbon production facilities. The focus for the audits was the adequacy of the safety management systems in place to control hydrocarbon containment and included both design and operational aspects. The paper discusses the principal findings from the audits and describes actions required to further improve process plant integrity management over the lifecycle of an offshore installation.
Crew Resource Management for Offshore Production and Maintenance
Authors: Flin R. , O'Connor P. , Mearns K. , Gordon R.
Published: December 2007

This paper describes a project sponsored by 13 companies and the HSE (OSD) to apply a form of human factors training called Crew Resource Management (CRM), which is widely used in aviation, to the training of offshore platform teams. The aim of the project is to design and evaluate the training to improve safety, productivity, and to reduce down time on offshore installations. A prototype course has been developed with support from a major operator who is sponsoring the project. The training is delivered over two days, and consists of six core topics (situation awareness, decision making, communication, team working, fatigue and stress) established from the findings of our own research concerning human factors offshore and our own experience of designing CRM courses for offshore emergency response teams. Feedback from the courses was generally positive, however, more work is required to tailor the course specifically for offshore teams.
Simulation Analysis of Lean Alternating Rich Gas Injection in a Massive Turbidite Reservoir
Authors: Beare P. , Cockin A.
Published: December 2007

Stranded gas and environmental concerns are leading more operators to consider gas reinjection which, if poorly planned, could lead to a loss in reserves. This paper reports on extensive compositional simulation studies which were performed on a high permeability turbidite reservoir to investigate ways of obtaining benefit from the injection of an apparently immiscible gas stream.

A lean alternating rich horizontal gas flood scheme, using separator streams, was identified as being attractive. The ratio of lean to rich gas was examined and an optimum identified which allowed the greatest volume of lean gas to be sequestered into the reservoir whilst increasing recovery by 10% OIIP above a base waterflood for the reservoir studied.

In addition, sensitivities were performed to investigate the impact of geological uncertainties, the use of water as a buffer, and varying injection rates and total injection volumes.

This paper illustrates that the latest high definition geology and simulation models can now unlock the potential of such novel gas injection schemes. In the past, models were too coarse and numerical dispersion dominated the process. This effect was investigated in the grid refinement sensitivities that were done in preparation for this project.
Chemical Gas Shut-Off Treatments in Brunei
Authors: van Houwelingen J.
Published: December 2007

In BSP layered reservoirs where thin oil rims are overlain by gas caps, oil production can be severely hampered by high gas/oil ratios. The negative consequences include reduced oil rates and oil recovery, early shut-in of production wells, environmental pollution resulting from excessive amounts of flared gas, loss of energy drive, downstream processing constraints and problems.

Oil production can be improved by means of a gas-blocking foam barrier in the near wellbore area.

The Gas Shut-Off (GSO) foam treatments can be applied through tubing by means of bull-heading and are therefore especially suitable where selective placement using straddle packers is not possible. A wet foam is injected non-selectively in oil as well as gas bearing sand layers. However, the wet foam will only develop into a barrier of dry foam as a result of the high shear from free gas in the gassed out layer(s). This effect allows wet foam placed in the oil layers to be back produced relatively quickly.

Key success factors for application of foam barriers are the optimum control of placement of the barrier-forming material and selection of the foams with the maximum gas-blocking ability. Selecting suitable foamer systems can only be done by means of laboratory flow tests at the prevailing reservoir conditions due to the interaction of the foam forming surfactant with its interfacial environment.
Handil Field: Three Years of Lean Gas Injection Into Waterflooded Reservoirs
Authors: Gunawan Sugianto , Caié Didier
Published: December 2007

The giant Handil field comprises of more than 500 hydrocarbon accumulations, in structurally stacked and compartmentalized fluvio-deltaic sands.

Most of the accumulations consist of a large column of saturated oil underlying a gas-cap, trapped in reservoirs with good rock properties, and have been produced by water injection or strong natural water drive.

In 1995 five reservoirs, representing nearly 1/5 of the field's total OOIP and which had reached their final stage of waterflood development - 58% of the total oil in place had already been produced - were submitted to a further development with lean gas injection to increase the ultimate oil recovery.

To date, after 3 years of gas injection, the recovery factor for these 5 reservoirs has increased by 1.2% of the oil initially in place and the project is considered both a technical and an economical success.

The predominant drive mechanism with lean gas injection have been confirmed by field data. The previous decline of oil productionhas been stopped and the oil rate is now stabilizing. The main monitoring challenge has been the control of gas cycling for most of the producers, particularly during periods of higher injection rates to compensate low injection periods imposed by gas availability.

The very close monitoring of the wells and reservoirs performance, the numerical simulation and material balance studies, have helped to better understand the mechanisms involved and have to led a revised and more efficient policy to maximize oil production.

The experience gained and the analysis of this 3-year old project gives the confidence to pursue the extension of the lean gas injection development to others reservoirs of Handil field.
Air Injection - Cost Effective IOR Method to Improve Oil Recovery from Depleted and Waterflooded Fields
Authors: Surguchev Leonid M. , Koundin Alexander , Yannimaras Demetrios
Published: December 2007

In the past air injection has found a wide application as a recovery method of heavy oil. Air injection into light oil reservoirs is a different process than heavy oil combustion. Significant increase in light oil production under air injection can be achieved with enhancement to the economics. The main agent of the process is air which can be regarded as an inexpensive and easily available. A total consumption of 5 to 10% of the remaining oil in place can be expected to maintain a propagation of the in-situ oxidation process. The flue gas and steam generated at the combustion front are stripping, swelling and heating contacted oil. The light oil is displaced at near-miscible conditions with complete utilization of injected oxygen. The process can lead to a high recovery within a relatively short period of time. The process can potentially result in all remaining oil in place being produced. The propagation of the combustion and displacement fronts in the reservoir can be sometimes uncertain. Monitoring and control of combustion front movement is important.

The potential of air injection process for an offshore field in the North Sea was evaluated. A simulation reservoir model accounting for chemical reactions, stochiometry and thermal aspects of the combustion process was used. History match simulations of the combustion tube experiments calibrated the fluid description in the simulation model. Application of air injection as primary, secondary and tertiary oil recovery process was evaluated. The simulation results showed a high efficiency of air injection if applied at a late stage of field production. Secondary air injection potential to improve oil recovery after depletion was estimated at 10% of STOOIP in comparison with secondary waterflooding, while tertiary air injection was estimated to improve waterflooding by additional 5% of STOOIP. Air injection in the light oil reservoirs at late or mature production stage will increase oil recovery at low extra cost and extend the economic life of the fields.
Application of Hydrocarbon Gas Miscible Flooding for Water Flooded Reservoir
Authors: Shimizu T. , Takahashi K.
Published: December 2007

Within the next decade, the potential for application of gas miscible flooding process can be enormous, particularly, in those reservoirs currently under waterflood. In general, reservoir pressures of these oil fields are maintained at relatively high pressure, which is favourable for application of gas miscible flooding. We conducted a feasibility study to investigate the application of hydrocarbon gas miscible flooding in an oil field in Middle East offshore area. This oil field has a plan to utilise the high pressure hydrocarbon gas produced from deeper gas formation beneath the target oil reservoir, as the injection gas. A series of laboratory tests, comprising of: (1) Phase behaviour tests, (2) Slim tube displacement tests and (3) Composite core displacement tests, were conducted to characterise the miscible process in the crude oil-injection gas system. With the help of phase behaviour tests such as swelling test and multiple-contact test, the equation of state (EOS) parameters were fine-tuned. The minimum miscibility pressure (MMP) was determined by the slim tube displacement tests and also a set of representative EOS parameters were successfully verified by simulating slim tube displacement performance. As the MMP is still below the current reservoir pressure, the composite core displacement tests were conducted to evaluate the displacement efficiency at the current reservoir pressure as the tertiary oil recovery after water flooding. The test results showed that more than 80% of residual oil after water flooding could be recovered. Finally, the compositional reservoir simulation studies for the sector model of the target oil reservoir were conducted and it too, indicated that hydrocarbon gas miscible flooding could be feasible in such a high water-saturation oil reservoir.
Dynamic Interaction Between CO2 Gas and Crude Oil in Porous Medium
Authors: Siregar S. , Mardisewojo P. , Kristanto D. , Tjahyadi R.
Published: December 2007

This paper is based on laboratory research which is focused on the potential applications of CO2 gas, existing in different reservoirs in Indonesia, especially in the D-Alpha Gas Reservoir in Natuna Sea. CO2 gas as an injection fluid into oil reservoirs has been a well recognized and well tested Enhanced Oil Recovery (EOR) method, because CO2 dissolves easily into oil, it reduces oil viscosity, and it can extract the light components in oil at sufficiently high pressures. The technical contributions that can be derived from this paper are: first, the cost of disposal of CO2 produced with natural gas can be saved, second, CO2 injected into nearby Natuna oil reservoirs will increase oil recovery of those reservoirs, third, the best method among several alternatives offered in this paper to maximize the benefit in recovering more oil can be selected. There were three objectives we wanted to achieve in these laboratory experiments. The objectives are to obtain oil recovery performance and to identify the interactions between fluids as a result of, first, CO2 dissolved in Water (carbonated water) Injection, second, CO2 slug and chase fluid injection, and third, CO2 injection with the addition of a surfactant slug and water into oil reservoir. The results showed that the cemented sand core delivered consistent results during the whole series of experiments. The sandpack has apparently altered during the experiments. The scaling coefficient calculations have shown that all displacement fronts are stable. All displacements have shown that oil recoveries with these methods are higher than with waterflood only. The observations on different displacement angle have shown that gravity plays an important role in the recovery process, so does CO2 gas concentration in injection water, CO2 slug size and surfactant concentration. It has been observed also that there are optimum values for those parameters, meaning that above those optimal, there is no increase in oil recovery. We conclude that these methods could offer alternatives in improving oil recovery, even after waterflood, also that the operation parameters should be optimized to maximize the benefit.
Field Test of the Indigenous Microbes for Oil Recovery, Ledok Field, Central Java
Authors: Yusuf A. , Kadarwati Sri , Nurkamelia Nurkamelia , Sumaryana Sumaryana
Published: December 2007

LDK132 was chosen to be implemented of MEOR technology using "huff & puff" method. Water and oil from Ledok Formation were taken at the wellhead. No LDK-132 core was available, only cores from LDK-209 and LDK-P1 were found. Core plugs could not be made from the former due to very tight conditions with the permeability of only 0.458 md. The latter with the permeability of 140 md was ready for the microbial core flooding (MCF) tests. A standard core (Clas-sach) from Scotland was also be used to compare with the native core's result. The MCF tests were conducted on reservoir conditions upon the native core gave an increase 12.58% of Sor, while the standard core yielded 21.22% of Sor. The first cycle, conducted on 8 July 1999, consisted of 135 barrels of microbes enriched with KKL-11 and M4+ media, were injected through annulus of LDK-132. The result showed an increased of oil production rate, from 8.18 BOPD before the injection to 12.27BOPD, hopefully, after the injection.
Resin Sand Consolidation In Baram Delta, Sarawak. Case Study On Resin Performance versus Internal Gravelpacking With Acid Prepacking
Authors: Karian Mohd Awallizam , Salleh Alias , Haron Jamaludin , Sura Mohamed Adzman Mohamed , Rashid Ruziean A.
Published: December 2007

Chemical sand consolidation (SCON) is a type of sand exclusion which withholds unconsolidated formation from disintegrating and producing loose grains into the wellbore. The produced sand can lead to plugging off completion accessories and eroding surface facilities which eventually, over long period of time, will hamper production of a well. Most of the time, a well needs to be shut in and some oil reserves will be left behind the casing. It requires investment in bailing out the sand from the well or may be to the extend of incurring high investment to workover the well.

Sand exclusion with internal gravelpacking (IGP) has been proven in Baram Delta field, Sarawak since early 60's. In early 90's, acidprepacking was introduced as part of gravelpacking job for better placement of gravels in the perforation tunnels. Historical performances show that the well has less skin than the conventional gravelpacking as the acid used can clean up the perforation tunnels and place the gravels inside them. The technique proved that the well flushed with acid prior to gravelpack job can sustain production much longer and at higher rate.

There are many chemical SCON (e.g. phenolic, epoxy, and furan) available in the market, but the project team decided to use furan resin mainly due to its economic viability. At the end of 1998, furan resin was applied in one of the Baram wells and it had improved production rate and much less skin compared to the well using IGP in the same reservoir package. Sand treated with resin is capable of delivering about 1000 bopd from 15 ft. of perforation interval compared to only 400 bopd in 49 ft. IGP perforated interval in another typical well.

In Baram Delta case even with snort perforation interval, the sand treated with resin can potentially deliver higher production than the sand controlled with IGP. The success of the pilot furan resin application are mainly due to the combination of a good drainage point selection, drilling practices, and cooperation between the production team and the project team during the production phase.
Study on the Mechanism: How Polyacrylamide Influences the Microscopic Properties of Produced Liquid
Authors: LiYan Qiao , Xiuhong Zhang , Fengling Zhao
Published: December 2007

The mechanism how polyacrylamide (PAM) influences the properties of produced liquid were investigated by means of the measurements of microscopic properties of oil-water interface. The resluts show that the presence of PAM results in significant increases of membrane strength and electrical property of oil-water interface, and decrease of interfacial tension. The tendencies of the variation were analysed and some suggestions on how to improve separation efficiency were proposed as well.
A Simulation-Based Spreadsheet Program for History Matching and Forecasting Shale Gas Production
Authors: Sawyer W. K. , Zuber M. D. , Williamson J. R.
Published: December 2007

This paper discusses the development and application of an Excel spreadsheet program for history matching and forecasting gas production from shale wells in the Appalachian, Michigan, or Illinois basin. The program is simulation-based and uses 1,000 to 3,000 simulation runs to a maximum time of 30 years. The simulation runs are made using a matrix of key reservoir parameters specific to the area of study. The output gas and water production from the simulation runs is incorporated into a worksheet in such a manner that any single forecast may be easily selected. The user selects a combination of input parameters from dropdown menus, and graphs of simulated gas and water production are instantly generated on the main worksheet screen.

Observed gas and water production data are entered into a separate worksheet for history matching and are plotted together with the simulated data. On the main worksheet, the drop-down menus are used to find the simulation input parameters that result in the best overall history match. Once a match is obtained, the user may easily export the 30-year simulated gas forecast for economic analysis.

This tool provides a simple method to quickly analyze short-term production data when no other means is available. Also, this tool can be easily adapted to different geological settings including shales, coals, and sandstones.
A Novel Lightweight Cement Slurry And Placement Technique for Covering Weak Shale in Appalachian Basin
Authors: Kulkarni S.V. , Hina D.S.
Published: December 2007

Cementing of casings over weak formations has always been a challenge, especially in the case of multiple zone completions where the zones are spread over large intervals.

Devonian Shale wells in Appalachia model similar difficulties. Frac gradients as low as 0.30 psi/ft are common in these naturally fractured zones. Cement fill-ups of up to 3500 feet are required to allow for up to 7 stage completions. Commonly, these wells have been cemented using two stage cementing or by planning for a squeeze after the primary cement job.

A lightweight cement blend was introduced in 1997 to achieve the entire fill-up with the primary cement job only. This blend provides the flexibility of density alterations from 11.0 to 14.0 lbs/gal (ppg) and is extremely easy to mix and pump. Another advantage of this blend is its ability to achieve gellation very quickly in spite of its high water content. A silicate component in the slurry efficiently ties up the excess water.

The job design utilized to place a long cement column across the weak and naturally fractured shale has proven to be very critical. A minimal amount of water pumped ahead ensures lowest possible hydrostatic pressure for the bottom most shale zone.

A single stage cement job offers several advantages. Cost savings in excess of $ 10,000 per well can be realized if the desired cement fill can be successfully obtained with a single stage job. Elimination of the stage tool and the ability to run frac baffles are the major contributors to the cost savings.

Through February 1999, this lightweight slurry was used to cement 65 wells. The available data indicates that sufficient cement fill was obtained to cover all the desired zones in more than 60% of the wells. The success rate increases to 78% if certain avoidable factors are eliminated. Cement fill-ups of as much as 4300 feet have been obtained with this slurry.
Practical Methods to Improve Storage Operations - A Case Study
Authors: Brown K. G. , Sawyer W. K.
Published: December 2007

A case study is presented in which a storage operator in the northeast US used easily obtainable data to: (1) accurately quantify both existing and potential deliverability of the reservoir; (2) identify bottlenecks in downhole and surface facilities that reduce maximum deliverability; (3) resolve inventory issues by determining the effective reservoir pore volume; (4) demonstrate the feasibility of turning the working gas volume multiple times per season; and (5) determine the optimum horsepower requirements to turn the working gas volume multiple times per season. All of this was accomplished by analysis of inexpensive and easily collected data.

The general optimization process used is outlined and discussed, as well as the limitations of the approach. The value of this optimization process is demonstrated by presenting field case histories that review the results of the optimization process and the implications to the storage operator.
Multilateral Tieback Insert Provides a Low-Cost, Sealing Multilateral Junction
Authors: Lindvall Jonas , Hengeveld Bas , Al-Asmi Moghrob , Chadwick Robert , Dewey Charles , McGarian Bruce
Published: December 2007

The Amin Field in Southern Oman is an excellent example of how multi-lateral technology catapulted an oil field from being an unattractive development to a highly attractive investment in the budget constrained late nineties. Despite being discovered in the mid seventies, development of the Amin Field did not really take off until horizontal drilling had secured a firm foothold, and only then with the assistance of multi-lateral technology. During the development of the Field the multi-lateral design was continually technically and economically optimized. This optimization, however, led to the unexpected plugging of the lower lateral by shale which ingressed through the milled casing window from the overlying cap rock. This in turn led to unsatisfactory economic performance of the streamlined multi-laterals and prompted immediate action. The Tieback Junction Sleeve (TBJS) was developed and tested primarily to combat the shale ingression and to provide a sealing multi-lateral junction. To date, extensive yard testing of the system has been undertaken and three complete TBJS systems have been run and tested in the Amin Field. All indications suggest that shale ingression have halted and that the junction is truly sealing.
Hse Management System Challenge
Authors: Ibrahim Reda
Published: December 2007

It is generally accepted that the effective management of HSE is an essential aspect of drilling industry. This is particularly so during a period of manpower and cost reduction when it is important to ensure that budget constraints do not lead to lower standards of, for example, manpower training or equipment maintenance. Indeed, it is in these very circumstances that it must be recognized that properly directed expenditure on HSE can lead to an overall reduction in costs.

The management process is often described in terms of a simple control system. The manager must establish the overall objectives, develop and implement plans to achieve the objectives, and then monitor progress and exercise control until the ultimate goal is achieved.

The real challenge facing management is to organize, equip and motivate the two different operations group (offshore and onshore) of personnel to have something done. This applies equally to HSE although the ultimate aim is quite different since it is to ensure that certain things never happen. Having this accepted by managers and supervisors who are accustomed to being judged on their achievements is a particular difficulty we have to face.
Formation Drillability-Definition, Quantification and Contributions to Bit Performance Evaluation
Authors: Mensa-Wilmot Graham , Calhoun Bill , Perrin Van P.
Published: December 2007

Current improvements in bit performance, though normally attributed to advancements in product development1,2, have greatly benefited from the science of formation characterization. Determination of rock mechanical properties, such as bulk compressibility, Poisson's ratio, internal friction angle, shear and compressive strengths from well log data continues to improve the bit selection and application processes. In fact, product development would not be at its present pace, without the influences of formation evaluation.

Several analytical methods3,4 have been developed by the industry for formation characterization purposes. Although these tools are effective, most of them fall short when there is a need to predict the performance of a given bit in a known field. In addition, they present a micro-scale evaluation of the formations to be drilled, making it difficult to establish and compare drillabilities in a given field or between different fields. Additional disadvantages of the current evaluation methods are that they presumptuously draw parallels between formation hardness and drilling difficulty, without establishing the relationships required to make the needed comparisons.

This paper will present a new bit performance evaluation parameter – formation Drillability (FD). It will establish a process for the determination of FD, which combines the different rock mechanical properties into a single dimensionless parameter. This approach addresses the limitations of the current evaluation processes by establishing an effective method for bit performance evaluation and prediction. FD establishes a macro-level evaluation process, which enables drillabilities to be quantified for different fields. Most importantly, FD improves operational efficiency by enhancing the development, selection and application of all types of drill bits.
Improving Drilling Efficiency Through the Application of PERFORM Performance by Risk Management
Authors: Anadrill W. D. Aldred
Published: December 2007

A new initiative to enhance drilling performance has been introduced to the industry. The initiative is based on close cooperation between the Operator and the Service Company as well as the integration of planning and real time drilling solutions to significantly reduce operational cost and non-productive time.

The paper shows how a risk management and loss control framework can be used to combine the technical expertise and drilling measurements provided by Schlumberger, with the knowledge and experience of the operators to develop solutions for enhanced drilling performance. Teamwork and establishment of good communication systems are essential factors in getting the solutions implemented.

Some of the key drilling areas where the strategy and tools have been applied are:

Stuck Pipe and Lost in Hole (LIH) Avoidance Drillstring Failure Prevention Wellbore Stability and Losses Drilling Efficiency, ROP and Bit Optimization Pore Pressure analysis and Influx prevention

This paper describes the experience of the PERFORM strategy applied in several locations around the world. Examples will be presented from projects that have been completed in a range of geographic and drilling conditions, where clients have reported reductions of NPT from an average of 40% to 4%, finishing hole section 10-14 days ahead of schedule.
Validation of Carbonate Matrix Stimulation Models
Authors: Fredd C. N. , Miller M. J.
Published: December 2007

The successful matrix stimulation of carbonate reservoirs requires that live acid penetrate past the formation damage. Effective acid penetration is facilitated either by transport through natural fractures or the formation of dissolution channels (wormholes) during the acidizing process. The optimal formation of wormholes and/or transport of live acid along natural fractures depends on the rate of reaction between the acid and the formation minerals, the rate of acid transport to the mineral surface, and the rate of acid convection along the wormhole and/or fracture. There are three prevailing theories in the literature that estimate the efficacy of acid stimulation treatments in carbonate formations. These theories predict the conditions at which wormhole formation occurs most efficiently and are based on the existence of: 1) an optimum injection rate at a transition between reaction-rate limited and fluid-loss limited regimes, 2) an optimum Peclet number, and 3) an optimum Damköhler number.

The models are compared with a large set of experimental data representing a wide range of conditions encountered worldwide. The results show the conditions under which each theory is most appropriate. Parameters studied include injection rate, temperature, and fluid-mineral system. Validated models are then used to simulate skin evolution during actual matrix acidizing treatments. Results of the laboratory and field validations highlight gaps in the current technology and provide directions for further investigation.
Development and Deployment of a Scale Squeeze Enhancer and Oil-Soluble Scale Inhibitor To Avoid Deferred Oil Production Losses During Squeezing Low-Water Cut Wells, North Slope, Alaska
Authors: Jordan M. M. , Graff C. J. , Cooper K. N.
Published: December 2007

The paper outlines the experimental work that has been carried out to develop an effective treatment strategy for production wells, specifically those with electrical submersible pumps (ESP’s) that suffered significant performance impairment at water cuts of less than 5% due to carbonate scale deposited within the ESP’s. These Alaskan production wells had been treated for a couple of years using aqueous based scale inhibitor squeezes. Many of these treatments resulted in a significant 10% to 20% reduction in the oil production rate following the squeeze. The damage mechanism was investigated by coreflooding and revealed to be a combination of water block and relative permeability effects. Following the damage investigation coreflood, a second study was undertaken to investigate a chemical treatment to remove the damage already present within the near well bore and prevent further deposition of scale. The result of this test program was the development of a treatment strategy which used a solvent package followed by an oil soluble scale inhibitor. Field results of this type of treatment suggest that the wells treated with this chemical system did not suffer any reduction in oil production rate and were effectively protected from carbonate scale. Wells that had been damaged by the previous aqueous treatments could be stimulated and the lost oil production recovered. Reference is also made to the development of an improved aqueous based squeeze treatments for the treatment of higher water cut wells.
Designing and Completing High-Rate Oil Producers in a Deepwater Unconsolidated Sand
Authors: Porter D. A. , Johnston R. A. , Mullen M. E.
Published: December 2007

The Troika Subsea development project has produced the top four hydrocarbon producing wells in the Gulf of Mexico – three wells each delivering greater than 40,000 STBOE/D sustained rate. This paper will give the reader an overview of the completion designs and installations, but equally important, what lessons we learned to apply on our next deepwater high rate producers.

The Troika field is located in 2700’ of water and was a fast paced development project which was delivered (from discovery to first oil production) in only 39 months – a deepwater industry record! This subsea development consists of five subsea wells clustered around a production manifold and tied-back 14 miles to the host platform. Many well design aspects, various technologies, and timing issues had to converge quickly for the success of this project.

Completion practices will be reviewed and resulting productivity performances will be charted. The following areas will be discussed: Well performance historyPerforating practicesFluid loss control practicesSand control operationsTubing installationFlowback operationsSubsea operationsBatch operationsPersonnel and training
Optimizing Perforating Strategy in Well Completions to Maximize Productivity
Authors: Underdown D. R. , Jenkins W. H. , Pitts A. , Venkitaraman A. , Li H.
Published: December 2007

The Britannia field is a gas producing reservoir operated jointly by Chevron and Conoco. Prior to completion of the wells, two major concerns were raised: potential sand production (perforation stability), and the optimum underbalance (for zero perforation skin) during completion. Theoretical models were used to predict the optimum underbalance based on log derived formation properties. Using detailed log permeability data numerous simulations were carried out to choose the gun, charges, shot density and perforating strategy for optimum productivity. Different shot densities and charges were used in different sections of the formation based on simulation results as opposed to choosing perforation parameters based on average well properties.

Experiments were conducted to confirm the theoretical underbalance predictions and to investigate the stability of perforation tunnels at high underbalance pressures. Reservoir and outcrop core samples were perforated at simulated downhole conditions in the laboratory at different underbalances based on values obtained from the model. Flow performance evaluation of the perforated reservoir core samples confirmed earlier conclusions on the sensitivity of the formation to aqueous wellbore fluids (brine). The results also confirmed the stability of the perforation tunnels at high underbalance. An underbalance value of 1000 psi used in the outcrop sample tests indicated near zero perforation skin. Perforation strategy for the North Sea field was chosen based on the results from the study. Well performance analyses of 12 of the wells completed indicate low to negative skins. The information is presented in this paper as a case of how to design a good perforating job and also to emphasize the need to study optimum underbalance for gas formations.
Application of a New Measurement Technique for Organic Acid Additives in Stimulation Fluids
Authors: Taylor K. C. , Al-Katheeri M. I. , Nasr-El-Din H. A. , Ahmed I.
Published: December 2007

An analytical method was implemented to simultaneously measure the concentrations of acetic, citric and formic acids in stimulation fluids. This method was not previously available for acid stimulation treatments. Capillary electrophoresis is used for rapid and accurate measurement of these organic acids in concentrated hydrochloric acid and in highly contaminated spent acidizing fluids. Commonly used titration methods are not effective at low organic acid concentrations or when more than one organic acid is present. Acetic, citric and formic acids have been used extensively in Saudi Aramco fields over the last few years as stimulation fluids and as acid additives. Citric and acetic acids are frequently used in acid treatments as iron control agents.

The following conclusions are made: A method for the simultaneous measurement of acetic acid, citric acid and formic acid was developed and evaluated.The method is linear in the range of 2 to 200 mg/l of organic acid in diluted samples. Field samples will normally be diluted by a factor of 200 to provide a range of 0.02 to 2.0 wt% of organic acid.The method can be used at concentrations from 200 to 1667 mg/l, but has a nonlinear response in this region.Sample requirement is less than 5 ml in most cases.Reproducibility of the method was excellent. Relative standard deviation of organic acid standards was less than 1% at 200 mg/l, less than 3% at 20 mg/l and less than 10% at 2 mg/l.The detection limits of the method are 0.25 mg/l for acetate, 0.4 mg/l for formate, and 1 mg/l for citrate, based on a signal to noise ratio of 3 to 1.For acetate and formate measurement, no interference occurred with chloride up to 1000 mg/l, calcium up to 565 mg/l, iron (II) or iron (III) up to 500 mg/l, or sulfate up to 859 mg/l.For citrate measurement, no interference occurred with chloride up to 1000 mg/l, calcium up to 350 mg/l, or sulfate up to 859 mg/l. Iron (II) and iron (III) caused interference at concentrations of 10 mg/l.

The method was used to simultaneously measure organic acid concentrations in coreflood samples and in field samples from acid stimulation treatments.
Successful High-Pressure/High-Temperature Acidizing With In-Situ Crosslinked Acid Diversion
Authors: Buijse M. , Maier R. , Casero A. , Fornasari S.
Published: December 2007

This paper describes a very successful acid stimulation treatment performed in AGIP’s Trecate-Villafortuna Field. The matrix acidizing treatment used in-situ crosslinked acid (ICA) as the diverting agent. The treatment is unique because it represents the highest temperature application ever attempted for such a system and falls under the definition of high-pressure high-temperature (HPHT).

The design process included temperature simulations, detailed laboratory testing, and a review of acid formulations that were used successfully in the Trecate-Villafortuna Field and elsewhere. Temperature simulations indicated that cooldown from the bottomhole temperature (BHT) of 180°C to at least 150°C could be achieved despite the high treating pressures that limited injection rates. Even after cooldown, serious concerns about corrosion and the effectiveness of the ICA system still existed. Laboratory support included fluid optimization for high-temperature application of the ICA. The flow tests enabled the selection of the most appropriate base acid systems and demonstrated that the ICA system would indeed function at the predicted high temperatures.

Success of the treatment must also be attributed to the operational planning and close attention to experience gained from previous stimulation treatments. The execution of the treatment used all of the components considered to be state-ofthe-art in matrix acidizing treatment execution and evaluation: prestimulation injection tests, spotting of acid with coiled tubing (CT) to help reduce injection pressures and improve zonal coverage, the use of the Maximum Pressure Maximum Rate Diversion Technique (MAPDIR), and real-time treatment pressure monitoring.

The paper will present job procedures and a detailed treatment pressure analysis. It will also give details on the changes in injectivity and the Productivity Index (PI) before and after stimulation.
Gas-Well Dewatering: A Coordinated Approach
Authors: Stephenson G. B. , Rouen R. P. , Rosenzweig M. H.
Published: December 2007

A joint fieldwide study was conducted by a service company and exploration company to determine the optimum method of unloading gas wells in which production was limited by accumulation of liquids in the tubing. Various methods of unloading the wells were analyzed and compared. After evaluating different techniques, gas lift was determined to be the most effective and economical means of dewatering. Each well's characteristics were analyzed to determine the gains that could be achieved through continuous unloading. The analysis also identified the key wells that would benefit substantially from artificial lift and defined the system requirements necessary to place these wells on gas lift. After establishing the wells' performance characteristics, a full-system model was constructed. The model was used to evaluate the impact of the gathering and compression systems on the overall optimization and development of the field. Two scenarios were examined to determine the optimum configuration of the gathering system, compressors and injection lines. A gas lift distribution system was designed and evaluated for both cases. Finally, an economic analysis was performed for each scenario to determine the most cost-effective method of developing a dewatering system for the field.
Analysis of Well Tests in Multiple Fractured Reservoirs - Field Case Applications
Authors: de Swaan A.
Published: December 2007

A simplified analytical model of pressure transients in fractured reservoirs with matrix-rock blocks of different sizes and/or properties was formulated and applied to field cases. In the applications, relations between traits in the pressure vs. time plots and rock properties are used to determine rock block sizes and block-size distributions from actual well tests.

Introduction

The mathematical description of flow in fractured reservoirs with rock-blocks of different properties has been an obvious development after the models of media with a single type of block. References 1 to 6 present such models. However, these papers present involved formulations of the block-to-fracture flow. As a result their application in the analysis of actual well tests is not straightforward.

Flow in fractured media is accurately represented as flow in the connected fractures medium plus a block-to-fracture component that depends on the blocks, or matrix, properties. In the present paper a simple formulation of such block-fracture interaction as presented in previous papers7,8 describing flow in single block fractured media is extended to the case with multiple rock blocks.

Theory

For multiple-block fractured media the interaction of blocks and fractures is governed by the relative frequency of occurrence (or just frequency) of a block type in the pay and by the block properties included in the block function of flow. The flow equation in radial (cylindrical) geometry with a multiple block to fracture interaction term is1,Equation 1

The Laplace transform of the former equation is,Equation 2

Block's function of flow.

The flow from or into blocks is described approximately by an exponential function, see Ref. 8, for a unit pressure variation at the blok's surface.Equation 3

or, in the Laplace domain,Equation 4

a is the ratio of block surface to block volume divided by a fraction of the block minimal dimension8,Equation 5

the value of a for other parallelepiped shapes, such as prisms or finite slabs, have values intermediate between the two values shown in Eq. 5.

The block function of flow reproduces closely results of exact functions of flow from parallelepipeds; but it is simple for computations and also for linking block properties to traits in the plots of transient pressure response vs. time.

Block's function of flow.

The flow from or into blocks is described approximately by an exponential function, see Ref. 8, for a unit pressure variation at the blok's surface.Equation 3

or, in the Laplace domain,Equation 4

a is the ratio of block surface to block volume divided by a fraction of the block minimal dimension8,Equation 5

the value of a for other parallelepiped shapes, such as prisms or finite slabs, have values intermediate between the two values shown in Eq. 5.

The block function of flow reproduces closely results of exact functions of flow from parallelepipeds; but it is simple for computations and also for linking block properties to traits in the plots of transient pressure response vs. time.
Expandable Liner Hanger Provides Cost-Effective Alternative Solution
Authors: Lohoefer C. Lee , Mathis Ben , Brisco David , Waddell Kevin , Ring Lev , York Patrick
Published: December 2007

Establishing and maintaining hydraulic integrity between liner hangers and the base casing in which they are set has long been one of the most problematic areas facing operators. With failure rates on pressure seals in overlaps now exceeding 40% in some regions, the need for a solution to this decades-old problem has reached a critical level. Although new approaches have included turbolizers for cementing overlaps, special cements, and liner-top packers, many problems still remain.

An operator and a service company are working together to develop a new drill liner hanger based on patented expandable-casing technology. This technology is being used to diametrically expand solid tubulars for a variety of drilling, completion, and remedial applications. The new liner system is designed to totally eliminate the liner lap by expanding an elastomer-coated casing into intimate contact with the casing from which the liner is being hung. Preliminary results indicate the new hanger design can result in load-carrying and burst capacities that exceed the capacity of the previous casing string. Furthermore, the overlap samples tested to date have all resulted in annular seals that have exceeded 10,000-psi differential capacities. In fact, casing has always failed during large-scale testing before any overlap leaks developed.

This paper discusses the design and application of the new liner hanger and presents laboratory and field-test results.
Foam Diversion Modeling Using a Bubble-Population Correlation.
Authors: Bertin H. J.
Published: December 2007

In a stratified porous medium, foam can divert the flow from high permeability to low permeability layers. This interesting behavior found several practical applications in some reservoirs and aquifers. Moreover, experimental results have shown that foam blocking effect is maximum when the layers are isolated, i. e., when there is no capillary crossflow. Foam blocking in high permeability layers can be explained through the concept of limiting capillary pressure, Pc*, which is the maximum value of capillary pressure above which liquid films separating bubbles are broken.

In this study, we present a numerical simulation of foam displacement in a stratified system made of two noncommunicating layers with a permeability ratio of 5.4.

Numerical simulations are performed using a bubble-population correlation that allows us to compute explicitly foam texture in each layer from the physical properties of the rock (porosity, permeability and capillary pressure). We observe clearly the blocking effect of foam in high permeability layer, diverting gas to low permeability layer, due to capillary pressure difference.

Numerical results are qualitatively in good accordance with experimental data published in the literature.