bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Drilling Practices - An Experiment in Cooperation
Authors: Brett J. Ford , Gregoli Mark K. , Gahan Brian C.
Published: December 2007

This paper presents the results of a Gas Research Institute funded study to test the following hypothesis:

"Broad-based benefit is created when drilling organizations systematically cooperate to identify and share successful practices".

To this end, eleven separate Successful Drilling Practices Studies (SDP) were commissioned with the following goals:Identify the most successful drilling practices for each of the study areas;Document these practices in enough detail (in the form of a complete drilling operations plan) to ensure practical application;Disseminate the successful practices; andMeasure the benefit derived from using the successful drilling operations plans.

The studies focus on the following eleven drilling environments:–Greater Green River basin (2 studies: South Moxa Arch Dakota formation and Wamsutter Almond formation),–Arkoma Basin (2 studies: Choctaw thrust and Jackfork Plays),–Cotton Valley Reef Play in East Texas,–Deep Austin Chalk (Texas),–Valverde Basin (Straw and Penn Sands, Texas),–Anadarko Basin (Watonga-Chickasha trend Morrow/Springer formations),–South Texas Gulf Coast (Wilcox Lobo Trend),–Deepwater (Green Canyon Area),–Extended-reach (South Pass Area) drilling in the Gulf of Mexico.

This paper outlines the methodology used to develop these SDP studies, and the benefits reported by operators who have used them. Evidence presented shows that broad-based benefit can be created when drilling organizations systematically cooperate to identify and share successful practices, and that the benefit ranges from 3% to 20% of total drilling costs, with an average benefit on the order of 10%.

P. 603
Conversion of a 1,500-ft Water-Depth Conventionally Moored Drillship Into an Ultradeep Water Dynamically Positioned Drillship
Authors: Vecchio John M.
Published: December 2007

In the late period of 1995 the demand for deep water capable drilling rigs out paced the availability for these units. This trend has continued throughout 1996 without signs of a weakening market in 1997. To meet this demand, fast track and economical solutions were required. This paper examines one solution, the OCEAN CLIPPER project, which began in early 1996 and completed in mid 1997

The OCEAN CLIPPER was a conventionally moored drill ship with 1,500 ft operating parameters, which during this period, was modified to be able to operate in ultra deep water depths to 7,500 ft and beyond utilizing the most sophisticated available technology. Station keeping has been modified to incorporate full dynamic positioning, and state of the art drilling equipment installed. The OCEAN CLIPPER solution represented the fast track economical resolution to this immediate need for the industry. The OCEAN CLIPPER project out paced new-build solutions for delivery at less than 50 percent capital expenditure.

This paper will examine the design and construction factors of this project. An overall schedule, total project cost as well as technical aspects will be discussed.

P. 669
Stopping a Water Crossflow in a Sour Gas Producer Well
Authors: Le Hello Y. , Ghesquiere P. , Woodruff J.
Published: December 2007

This paper presents a summary of the strategy and execution for intersecting and plugging at a depth of 2730m a significant water cross flow (10000-15 000m3/day) invading a depleted sour gas producer well. This operation was performed at the beginning of 1997 in the south west of France. To save time, the top part (0-2100m) of the damaged well was reused and the well side tracked through tile collapsed zone. Then Drilling along side the old well was resumed prior to intersecting the 7" casing and tile 3"1/2 DP. The challenge was also to stop the waterflow and to be able to definitively plug the well with cement.

Included in the presentation of this paper are:–Information regarding the cross flow between a water zone, the Albo Apien formation 2100 m TVD, and the gas reservoir formations 3600m TVD, generated by the collapse of the production casing.–Documents which present information concerning both the planning and execution phases of the project.–Various diagrams of summaries of ranging, milling available tools and their use during the project.–Short video film (5mn) made with a down hole camera showing the collapsed zone, the intersection area and the milled pipes.

This video is unique thanks to the indepth study of the subject and the quality of the images provided.

P. 841
Application and Analysis of Simultaneous Near Bit and Surface Dynamics Measurements
Authors: Macpherson J.D. , Jogi P. , Kingman J.E.
Published: December 2007

Axial, torsional and bending vibrations are all present in a BHA while drilling. The dynamic response of the BHA depends on many variables such as drilling parameters, BHA design, hole condition and inclination, and formation properties. Events such as bit bounce, forward and backward whirl of the BHA and bit, and drillstring resonance can occur during drilling. Some of these events are very detrimental and can cause drillstring component failures, twist- offs, etc.

This paper deals with the analysis of measured drilling vibration data from a field test that used both down-bole and surface vibration measurement devices. Surface sensors included dynamic axial and torsional strain gages and accelerometers, and a single axis magnetometer, all mounted in the drillstring above the rotary table. Down-hole sensors included an axial accelerometer, two orthogonal bending strain gages, dynamic weight on bit and torque strain gages and two orthogonal magnetometers, mounted in an MwD sub.

The analysis described in this paper involves (1) the determination of axial & torsional wave velocities in the drillstring, (2) their use in predicting resonant frequencies, (3) a comparison of predicted and measured resonant frequencies, (4) inference of down-hole dynamics using surface measurements (surface noise cancellation) including a comparison of results with measured down-hole data, (5) an example of the detection of BHA whirl using down-hole data, (6) an example of the detection of bit bounce using down-hole axial data, and (7) an examination of precession of the trilobed bottomhole pattern generated by a tricone bit.

The advantages of using either surface or down-hole dynamic measurements in identifying different drilling problems is demonstrated, as well as the inference of down- hole dynamics using surface measurements. Once drilling dynamics problems are identified, remedial action can be taken to reduce tool and bit failures while drilling, and to optimize the drilling process.

P. 857
Field Validation of a Foam Diversion Model: A Matrix Stimulation Case Study
Authors: Thomas R. L. , Ali Syed A. , Robert J. A. , Acock A. M.
Published: December 2007

Numerous foam diversion models have been developed during the past decade; however, none has been field validated. Field validation of any model used by the matrix treatment design engineer is essential. Without proper validation studies, the engineer cannot optimize the treatment design with any reliability. This paper addresses the field validation of a previously reported foam diversion model incorporated into a matrix treatment design simulator and offers guidelines for diverter selection.

A matrix-acidized well located in the Gulf of Mexico was used for validation of the foam model. In most cases, the simulator's bottomhole treating pressure (BHTP) prediction was within ±5% of the BHTP observed in the well during the foam diversion and acidizing stages. The two-phase, finite-difference simulator models foam flow in the matrix through modification of the relative permeability to gas. The simulator models surfactant adsorption, gas solubility and mineral dissolution with the corresponding permeability changes in a multilayer reservoir. The keys to the foam model validation are good well data and BHTP estimation.

For field validation, a downhole sensor package was used to record the bottomhole pressure and maximize the accuracy of the validation process. Post-treatment evaluation directed at model validation consisted of simulation of the actual treatment followed by a comparison of the simulated and actual BHTP. A detailed description of the foam validation process and the supporting well data are presented. This study indicates that a matrix treatment using foam diversion is not engineered until it is simulated using valid models. Additionally, the study indicates that foam diversion is not the best diversion technique to use in all wells.

Simulations support published laboratory data indicating that poor diversion (equal flow rates per foot) is obtained with foam slugs when a high-permeability contrast and/or damage contrast exist; however, simulations indicate that in most cases good diversion is possible using an oil-soluble resin or foamed acid. Guidelines for diversion type and technique are provided to assist the design engineer.
Operational Experience with Foam-Diverted Acid Jobs in the Gulf of Mexico
Authors: Morphy P. H. , Greenwald K. G. , Herries P. E.
Published: December 2007

This paper summarizes current field experience with remedial acid jobs on "horizontal" wells and long interval vertical completions at South Pass 61 Field in the Gulf of Mexico. Many of the learnings are based on downhole pressure data gathered during the acid jobs. By analyzing this data1-2-3, reasonable conclusions about the effectiveness of the stimulation treatment and foam diversion have been made.

The collection of this data and its analysis are becoming routine in areas where they can clearly be of benefit. This includes new fields, fields with poor stimulation success rates, and fields with large vertical or horizontal wells which require expensive acid jobs. SP 61 is a prime candidate for this type of study because the field has a historical acid job success rate of 11% and twelve horizontal wells, most of which are impaired. Collecting the data has been a profitable venture, since the cost of gathering the data for post treatment review is typically only $2000 to $5000 per job. This is insignificant when compared to the typical $150,000 total cost of a horizontal well acid job with coil, or the cost of avoiding the failure of one large $60,000 bullheaded acid job.

This paper offers two potential benefits. For those with Gulf of Mexico or analog completions, these results may be directly applicable. For others, this is a case study proving the value of evaluating the pressure response during an acid job. This evaluation's impact has been significant at SP 61, and it may be the only way to get data that was not collected during the field's development (e.g. acid's reaction with the mineralogy).
Acidizing Gas Wells in the Merluza Field Using an Acetic/Formic Acid Mixture and Foam Pigs
Authors: da Motta E.P. , Quiroga M.H.V. , Aragao A.F.L. , Pereira A.
Published: December 2007

Acidizing Gas Wells in the Merluza Field Using an Acetici Formic Acid Mixture and Foam Pigs

This paper presents the laboratory testing of acid compositions and the planning, execution, and evaluation of the acidizing operations performed in the Merluza gas field, located offshore Brazil.

Since the beginning of the production, the presence of calcium carbonate scale has been observed. Laboratory experiments determined that the most efficient acid mixture to remove that scale and to clean up perforations was 7% formic acid (HFor)/ 5% acetic acid (HAc) and that the best composition for matrix acidizing was saturated di-sodium EDTA. Regular HCl compositions were not recommended due to the nature of the tubing material (13Cr) and of the high reservoir temperature.

The use of foam pigs to keep the acid at the desired position and to prevent the reaction products from decanting to the formation, and the application of the organic acid mixture to clean up the perforations were very successful, increasing the gas production rate by 740.000 m3/day. Because of this, the matrix acidizing with EDTA was postponed. These results show that Hac/H for compositions are a viable solution to acidize wells where HCl cannot be used, such as HPHT wells, or where production equipment contain chromium.

P. 67
Filtercake Integrity and Reservoir Damage
Authors: Bailey L. , Meeten G. , Way P. , L'Alloret F.
Published: December 2007

Filtercake performance is of particular importance in openhole completions where formation impairment cannot be bypassed by perforation. Emphasis is placed on producing a thin, tough and highly impermeable cake to seal the wellbore during drilling. Once completed and the well is brought onstream, the filtercake is required to break down without the need for expensive clean up treatments. Filtercake integrity can then play an important role in the cleanup of a reservoir. Back production is assumed to cause the cake either to detach from the formation or rupture. Cake-rock adhesion and inherent filtercake strength are therefore important in determining how the cake breaks down to allow oil flow. If the cake-rock adhesion is strong compared to the internal strength of the cake, the cake may pinhole, or blister to allow flow. If it is relatively weak the entire cake may lift off cleanly. This latter case may cause further production problems if the cake subsequently seals the completion hardware.

This paper presents laboratory data on filtercake strength and its relation to cleanup by back-production for typical reservoir drilling fluids. Critical components are identified. The role of bridging solids particle size in determining the balance between adhesion and rupture strength will be demonstrated. Filtercake design to optimize removal through the exploitation of functional weak links will be discussed.

P. 111
Guidelines for Solving Sand Problems in Water Injection Wells
Authors: Morita Nobuo , Davis Eric , Whitebay Lee
Published: December 2007

Since formation failure and sand production problems in water injection wells are less common than in producing wells, no general guidelines on how to complete water injection wells has appeared in the literature. However, formation failure related sand problems in water injection wells are serious enough that they should be taken into account during the selection of a completion method. This paper provides information on field-observed sand related problems encountered in water injection wells, and discusses the mechanisms leading to sand problems. It reviews the injectivity efficiency of several completion options, and provides guidelines for selecting completion methods for water injection wells drilled through formations prone to sand production. The paper emphasizes that even though sand problems in injection wells are less severe than in producing wells, careful selection and design of completion methods for injection wells can significantly reduce the likelihood and severity of future injectivity problems.

P. 189
Micro-Mechanical Modeling of Perforating Shock Damage
Authors: Swift R.P. , Behrmann L.A. , Halleck P.M. , Krogh K.E.
Published: December 2007

Shaped-charge jet-induced formation damage from perforation treatments hinders productivity. Manifestation of this damage is in the form of grain fragmentation resulting in fines that plug up pore throats along with the breakdown of inter-grain cementation. We use the Smooth Particle Hydrodynamic (SPH) computational method as a way to explicitly model, on a grain-pore scale, the dynamic interactions of grains and grain/pores to calculate the damage resulting from perforation- type stress wave loading. The SPH method is a continuum Lagrangian, meshless approach that features particles. Clusters of particles are used for each grain to provide representation of a grain-pore structure that is similar to x-ray synchrotron microtomography images. Numerous damage models are available to portray fracture and fragmentation. In this paper we present the results of well defined impact loading on a grain-pore structure that illustrate how the heterogeneity affects stress wave behavior and damage evolution. The SPH approach easily accommodates the coupling of multi-materials. Calculations for multi-material conditions with the pore space treated as a void, fluid filled, and clay filled show diverse effects on the stress wave propagation behavior and damage. SPH comparisons made with observed damage from recovered impacted sandstone samples in gas-gun experiments show qualitatively the influence of stress intensity. The modeling approach presented here offers a unique way in concert with experiments to define a better understanding of formation damage resulting from perforation completion treatments.

P. 381
Near-Wellbore Formation Damage by Polyacrylates: Effects of pH and Salinity
Authors: Denys K.F.J. , Zitha P.L.J. , Hensens H.C. , te Nijenhuis K.
Published: December 2007

Near-wellbore Formation Damage by Polyacrylates: Effects of pH and Salinity

This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 0l-972-952-9435.

Polyacrylates are frequently added to drilling fluids in order to increase viscosity and limit formation damage. In this work we studied the influence of pH and salinity on the bulk flow behaviour and on the permeability reduction caused by polyacrylate retention in a porous medium. Two different retention mechanisms were observed: (non-stationary) core plugging and adsorption. The plugging mechanism could be avoided by adding phosphate to the solution causing a destabilization of polyacrylate aggregates. The permeability reduction in both cases was (strongly) dependent on pH and salinity on the injected water. In the alkaline regime, important for the application in drilling fluids. both the viscosity and the magnitude of the permeability reduction were relatively high. additives.

P. 431
Horizontal Gravel Packing Technique for Slim, Cased Holes in Highly Permeable Zones: A Single Well Case History
Authors: Upchurch E.R.
Published: December 2007

Gravel packing is becoming a common practice for controlling consolidated sands in horizontal wellbores. So far, horizontal gravel packing has been applied almost exclusively to open holes with screens in them, If a formation has a high permeability, and therefore a high fluid loss rate, placement of a gravel pack may be prevented by premature dehydration and bridging of the gravel pack sand in the wellbore/screen annulus, The usual method of preventing these high fluid losses and the resulting bridging is to damage the formation face prior to gravel packing, The damage mechanism is usually salt. calcium carbonate, or other particles that seal off the formation face. Once gravel packing is completed, the formation damage is (hopefully) remediated using acid or undersaturated brines to restore the completion's productivity. There is, however, a risk that the damage cannot be successfully removed once it is gravel packed against the formation face. Acid diversion is also a problem when attempting to remediate damage in an open-hole gravel packed completion.

This paper presents an alternative technique for performing a horizontal gravel pack in a high permeability zone while reducing the risk of permanently damaging the formation's permeability, The technique involves cementing casing through the horizontal completion interval and then shooting perforations in a horizontal orientation. The perforations can then be acidized with better diversion techniques than is possible in an open hole completion. A neutralized screen is then gravel packed. The horizontally positioned perforations provide a self-diverting gravel pack. The self-diverting nature of this technique makes it relatively insensitive to fluid loss; whereas, open hole techniques are very sensitive to fluid loss. The uncentralized liner rests on the bottom of the horizontal to provide maximum standoff from the perforations.

The above technique was applied at Thums Long Beach Company to a well with a 560 horizontal completion cased with a 4#1/2" liner (4.052" ID). The technique's acidizing phase, however. was not performed due to fishing concerns inside the slim liner. This paper presents a case history for gravel packing a 690' long, 2-7/8" slotted liner inside the horizontal 4#1/2" casing. To our knowledge, this is the slimmest horizontal gravel pack ever attempted. The gravel packing was performed successfully even though fluid returns were never established during the job. The lack of fluid returns is due to excessive fluid loss to the formation. The self-diverting nature of the horizontal perforations was the key to successful gravel packing. Production rates, on the other hand. were not as successful since we did not acidize the perforations prior to gravel packing. Comparisons between this well and open-hole horizontal gravel packs are made.

P. 463
Wellbore Cleanup in Horizontal Wells: An Industry Funded Study of Drill-in Fluids and Cleanup Methods
Authors: Burnett David B.
Published: December 2007

David B. Burnett

This paper describes the results of a two year study comparing the performance of a number of commercially available drill-in fluids (DIFs) used in horizontal well completions. The project was designed to provide a direct comparison of those fluids by measuring wellbore and formation damage and well cleanup in horizontal openhole completions in consolidated and unconsolidated formations. Thirteen different types of DIFs were evaluated including laboratory prepared and field samples of sized salt DIFs, synthetic base, polymer-carbonate based, and formate based DIFs. Screening tests were performed in single core (consolidated) tests without sand control screens. Later, radial flow-dynamic leakoff tests were performed in a multi-core test cell. DIFs were also tested in core wellbores modified to evaluate filtercake damage caused by production through sand control well screens.

Practically all DIFs exhibited low spurt loss and good filter loss control. These DIFs formed external filtercakes on the walls of the wellbore, but with little invasion into the rock. A number of cleanup practices were used to remove these filtercakes. HCl acid washes and soaks, dilute brine washes, solvent soaks, and oxidizer treatments were all evaluated. Two types of internal breakers were incorporated into sized salt systems as well.

We found that cleanup was not as effective as expected. Core materials exhibited low regained productivity (permeability) even after cleanup to remove wellbore damage. Low regained permeability was related to the nature of the DIF filtercakes and to the presence of simulated drill solids added to the DIFs. These materials caused the filtercakes to be tighter, more tenacious and harder to remove from the wellbore. Production of filtercake and filtercake residue from well walls also caused significant screen plugging. Polymer- carbonate DIFs showed greater screen damage than sized salt systems.

As we learned more about the causes of damage we modified our completion practices to incorporate new DIF formulations and new cleanup practices. As a result the average productivity regained went from 58% regained flow capacity in the first year of testing to 71% in the final year of the program.

P. 469
Fines Migration Control in High-Water-Cut Nigerian Oil Wells: Problems and Solutions
Authors: Ezeukwu Toni , Thomas R.L. , Gunneroed Terje
Published: December 2007

Although fines migration has been investigated in the laboratory and the field for more than 30 years, severe loss of production resulting from fines migration still exists in countless reservoirs. This field study evaluated organic and inorganic clay-control agents to determine their effectiveness to eliminate fines (silt and clay) migration in high production-rate wells. Four gravel- packed wells that exhibited severe fines migration problems subsequent to conventional hydrofluoric acid (HF) treatments were over flushed with an organic polymeric clay-control agent. The wells were acidized again after production had significantly decreased because of fines migration and over flushed with an inorganic agent to compare their performance Descriptions of the candidate selection and design procedures are provided with the chemistry of the clay-control systems and their control mechanism.

This paper supports previous laboratory results that found organic polymeric clay-control agents are not effective in eliminating fines migration owing to mechanical dislodgment. In most cases, production declined 50 to 90% within one year following organic clay-control treatments. Additionally, the onset of water production further increased the production decline rate because of increased fines migration. Following the inorganic clay-control treatments, fines migration was greatly decreased although the wells were producing at higher rates with higher water-cuts. The oil production one year after the modified treatments was more than double the production at one year following the organic clay-control treatments. Five to six years after the inorganic fines-control treatment production was equal or higher than the one year rate following the organic clay-control treatments.

P. 529
Mud Filtrate Invasion Profile - Its Influence on Wireline Logs and Hydrocarbon
Authors: Borah N.M. , Mallick R.K. , Choudhuri B. , Rathore Y.S.
Published: December 2007

Invasion of mud filtrate into permeable formations impedes accurate formation evaluation and impairs productibility of oil and gas reservoirs. The paper describes a case study to demonstrate the time lapse effect of invasion on wireline log response and its effect on hydrocarbon productibility.

P. 119
Production Optimization in Mature Fields Using Technology Integration of Production Logging, Horizontal-Well Technology and Water-Shutoff Techniques
Authors: Habib El Sayed , Osman Magdy S.
Published: December 2007

Water production started increasing from some Bapetco's oil/gas reservoirs with a subsequent drop in hydrocarbon production. Water movement in the reservoir was not well understood, and it was not clear whether zones of high hydrocarbon saturation still existed. Therefore, a saturation distribution study was initiated with the objective of increasing oil/gas production while decreasing water production. The geology of the fields was examined to select key wells for determining the water saturation using thermal neutron decay time logs. In wells with existing TDT* logs, the time-lapse technique was used to determine the change in saturation. In wells without existing TDT logs, the open hole saturation just after drilling was used to determine the change in saturation. The saturation changes were incorporated with the field geology to provide a good understanding of saturation over the entire reservoir. The integration of production log results, production geology and simulation data has led to a new picture. Water shut off using through-tubing bridge plugs was applied as a solution for the increasing water production. Other water shut off techniques were also considered. Unflushed zones were perforated to increase oil production. Using an updated simulation model, horizontal wells were planned to target unswept zones. One horizontal well was drilled so far with good result. The paper presents the successful integration of at least four different techniques in order to optimize reservoir performance.
The Role of Reservoir Management in Carbonate Waterfloods
Authors: Thakur G. C.
Published: December 2007

The need to enhance recovery from the vast amount of remaining oil- and gas-in-place in the carbonate reservoirs requires better reservoir management practices. Proper timing has a profound effect on the implementation of sound reservoir management technology on recovery efficiency. With this in mind, our goal should be to maximize volumetric sweep early in the project's life. Trying to squeeze more oil from marginal projects will generally yield marginal to average results. The purpose of this paper is to: (i) identify the major attributes of a successful waterflood asset management program, (ii) outline critical issues and technical areas, and (iii) document benefits received from a team approach to asset management, utilizing carbonate reservoir case studies.
Nitrogen Containing Organic Compounds as Corrosion Inhibitors of Mild Steel Corrosion in Oilfield Acids
Authors: Kumar T. , Vishwanatham S. , Emranuzzaman _ , Talukdar B. N.
Published: December 2007

The paper describes results of a preliminary laboratory study on corrosion protection of mild steel in 15% HCl and 3% HF used in acidization of oilwell by some N-containing organic compounds. Inhibition efficiencies were evaluated by metal loss and potentiostatic polarisation methods. The corrosion rate of mild steel decreased appreciably even in the presence of traces of the compounds. The extent of decrease in the corrosion rate was found to depend on the nature of the inhibitor and its concentration. Results of testing the additives in preventing corrosion of mild steel by the acid solution at different temperatures (30 to70°C) and exposure times (6h to 36h) at a fixed inhibitor concentration are also reported here. Thermodynamic parameters like heat of adsorption and activation energies have been calculated in the absence and presence of these organic additives. The nature of the film formed on the metal surface was analysed by infrared (IR) spectrum and relationship between structure of the organic compounds and inhibition effeciency has been explained.
Internal Corrosion Failure Model of Compressed Natural Gas Transmission Lines and Efficient Mitigation Programme
Authors: Saxena A. K. , Sharma V. K. , Chugh S. K. , Velchamy S. , Kumar Ramesh , Prakash Ram , Sharma B. K. , Dinesh R. S.
Published: December 2007

Corrosion aspects of oil field production facility continues to receive ever-growing attention because of increasing cost of energy and need for safe and reliable operations so critical for overall profitability. Failure of compressed natural gas transmission line, between Sanand and Jhalora oilfields is wide spread due to suspected internal corrosion and often required replacement. Intensive efforts have been made to study character of the problem. The investigations include an analysis of the internal environment of the pipeline and failure analysis of a failed pipeline sample including visual inspection, ultrasonic measurements, metallographic investigation, material property testing like hardness and tensile strength and gravimetric corrosion rate studies under simulated line conditions.

Significant high partial pressure of CO2 and presence of water induce internal corrosion which is accelerated due to erosional affect of annular mist flow inside the line. The synergistic effect of erosion-corrosion leads to execessive localized pitting and thinning of wall of transmission line leading to ruptures.

Continuous low dose addition of an oil soluble water dispersible amine inhibitor is found to be technically most feasible aspect to avoid system failure in future. The inhibitor had good film forming and film maintenance properties. The need to atomise the inhibitor to obtain suitable transport characteristics is emphasized.
Modeling Fluid Flow in Complex Naturally Fractured Reservoirs
Authors: Kamath J. , Lee S. H. , Jensen C. L. , Narr W. , Wu H.
Published: December 2007

We use a new numerical code to calculate single phase fluid flow in naturally fractured reservoirs. Our code is unique in that it can handle both complex fracture patterns and the coupling of the matrix and fracture flow fields. Our results show that details of the fracture statistics can become less important as the matrix becomes more permeable. We also find that the coupling of the matrix and fracture flow fields is very strong. We demonstrate the application of our code to develop grid block permeability values for use in continuum reservoir simulators.

Mapping subsurface fracture distributions for use in our code is a key challenge. We briefly present the results of a new methodology that uses physical models and geostatistical techniques to generate such data.
A New IPR's Establishment and Solution for Horizontal Wells
Authors: Huang Bingguang , Liu Shuzhi , Li Shunchu , Li Lianwu , Zhang Xinglin , Chen Zhengsheng
Published: December 2007

Many researchers find that when IPRs of a vertical well are used in a horizontal well, the results are not satisfactory. To be exact, the exponent type of IPR can not reasonably match the late part of the observed curve, while the binomial equation can not match the early stage of the curve very well. Bendakhlia et al1 combined the two equations into an equation, and applied it to describe the IPR of a horizontal well. They thought that the composite equation can better be used in a horizontal well, and verified the conclusion by means of numerical simulation results. However, the equation is only valid to an ideal well (a well without any negative or positive skin factor).

Considering Bendakhlia's work, the authors introduce a flowing efficiency R to establish a new IPR for horizontal wells so as to broaden its application. The new equation is suitable to both ideal wells and actual wells (damaged or stimulated wells). Moreover, this paper presents the solution technique to obtain unknown parameters in the formula for dimensionless IPR curves of a horizontal well according to steady well testing data. Several examples have shown that the new IPR equation can give satisfactory performance prediction results of horizontal wells. Its prediction accuracy is higher than that of the IPR developed by Bendakhlia et al. The relative errors of oil flow rates in an example are within 1.5%.
Do Fluid Loss Control Additives Perform As Claimed In Acid-Fracturing Treatments
Authors: Mumallah Naim A.
Published: December 2007

Acid is injected into an induced fracture to etch the walls and make passageways that remain open after an acid fracturing treatment for the reservoir fluids to travel to the well bore. Unfortunately, a substantial portion of the acid leaks off into the matrix surrounding the fracture. Acid leaks off through natural fractures or through the walls by forming wormholelike passageways into the matrix. To minimize acid leakoff fluid loss control additives are routinely incorporated in treatment pads. Which additive and how much to use for a given reservoir are always chosen arbitrarily.

This paper reports on a study of some variables that may affect acid leakoff through wormholes. The paper also presents results of an evaluation of the effectiveness of fluid loss control additives in acid-fracturing treatments. An apparatus was built that permitted the investigation of acid leakoff under dynamic flow conditions similar to what occurs from the fracture in acid fracturing treatments.

The results indicated that acid reacts uniformly and worm holes do not develop or propagate through chalks, regardless of the pressure difference between the fracture and the matrix surrounding it, if the calcite content of the chalk is less than 70%, and/or the effective permeability is less than 0.035 mD. The results also revealed that fluid loss control additives did not affect acid leakoff through worm holes; regardless of whether the additive was incorporated in the acid pad, in the viscous pad or in both.

Based on the results of the laboratory study acid-fracturing treatments were performed in the field with pads that did not contain fluid loss control additives. The results of field treatments confirmed the laboratory findings when wells stimulated with pads that did not include fluid loss control additives performed comparably to wells acid-fractured with pads that contained additives.

P. 575
Evaluation of Clay Stabilizers for a Sandstone Field in Central Saudi Arabia
Authors: Nasr-El-Din H.A. , Al-Mulhem A.A. , Lynn J.D.
Published: December 2007

An oil field in central Saudi Arabia produces super-light crude from a sandstone reservoir. The formation contains up to 2 wt. percent authigenic clays dominated by kaolinite and illite/montmorillonite mixed layer clays. To improve well productivity, a well stimulation treatment has been conducted on the producing wells in this field. The treatment introduces several fluids which might invade the formation and induce formation damage.

An experimental study was conducted to determine potential formation damage due to fines migration and clay swelling and design an effective clay stabilizer treatment. The work included performing coreflood experiments using reservoir cores at reservoir conditions (180 F and overburden pressure of 1500 psi). The critical salt concentration (defined as the salt concentration below which there is loss of permeability) was first determined. Several commercial clay stabilizers, cationic polymers, were evaluated. The effects of stabilizer concentration (0 to 2 vol. percent.), soaking time, and acids (15 wt. percent HCl) on core permeability were investigated in detail.

The experimental results indicated that the critical salt concentration (KCl brine) was nearly 5 wt. percent. Severe loss of permeability was observed when brines of lower salt concentrations were injected into reservoir cores. The effectiveness of clay stabilizer was found to be a function of chemical type and concentration. Some of the chemicals tested were not effective at concentrations less than 1.5 vol. percent. Others were effective clay stabilizers, but caused loss of injectivity at higher concentrations (2 vol. percent). After conducting a thorough investigation, it was found that these chemicals did not readily dissolve in water and formed fish- eyes. When these chemicals were injected into reservoir cores, they formed an external filter cake which caused loss of permeability. This problem was solved by good mixing of the stabilizer and proper filtration. Hydrochloric acid did improve the performance of at least of the clay stabilizers examined. Based on lab testing, a cost effective clay stabilizer was tested in the field at a concentration of 2 vol. percent. Field results indicated that the chemical did not cause loss of injectivity, and minimized formation damage due to fines migration and clay swelling.

P. 613
High Permeability Channels in Proppant Packs Containing Random Fibers
Authors: Howard P.R. , James S.G. , Milton-Tayler D.
Published: December 2007

This paper discusses laboratory studies to determine the nature of channel growth and stability in proppant packs with and without fibers. Tests were performed with proppant packs in three different types of experiments using natural sand and ceramic proppants, gas and water flow, and either perforations or an open proppant pack face. Proppant packs without fibers fail at low fluid velocities by the formation of voids at perforations or across the entire front of the proppant pack. Only when imperfect proppant packing was suspected did a channel form without fibers. Proppant packs with fibers form channels that are 2-10 cm wide depending on fluid velocity. The channel length increases in stepwise progression with increasing flow rate (velocity). The proppant pack on the either side of the channel supports the closure stress. Channels are stable over time at constant flow rate. Channels grew with fibers in all conditions tested. Random fibers mixed with the proppant extend the fluid velocity range for channel growth to much higher values.

P. 665
Designing a Remedial Acid Treatment for Gulf of Mexico Deepwater Turbidite Sands Containing Zeolite Cement
Authors: Rogers B.A. , Burk M.K. , Stonecipher S.A.
Published: December 2007

Ewing Bank 873 Field, developed from mid 1994 through 1995, produces from deepwater turbidite sands at an average depth of 11,000 TVD. Water depth at the platform is 775. In early 1996, pressure transient analysis of bottom hole pressure build-up surveys indicated increasing skins. Before pumping any type of remedial stimulation treatment, it was decided to test the recommended acid formulation in the lab. Acid corefloods were performed on composite samples from whole core using a typical 10% HCl/l .5% HF formulation. This acid formulation proved to be damaging as lab results indicated losses in permeability of up to 74%. A series of core floods were then performed on composite core samples to test the effects of various mud acid formulations, pre-flushes, post-flushes and acid additives. X-ray diffraction (XRD) and scanning electron microscope (SEM) analysis were also performed to help in determining the cause and mechanism of the damage. Results indicated that the loss in permeability was associated with acid additives which were causing fines migration and with silica gels precipitated as a result of the aggressive reaction of HCl with zeolite (clinoptilolite) within the formation. An optimum treatment formulation was identified, consisting of 10% Citric/1.5% HF acid, with no additives except corrosion inhibitor. This treatment was successfully applied in the field to five producing wells. Aggregate rate increased from 7400 BOPD to 16,000 BOPD and productivity index (PI) increased from 4.78 to 12.73 BOPD/psi of drawdown.

P. 693
Steam Oil Displacement and Vaporization of Minas Oil in Slimtubes
Authors: Benard J. H. , Richardson W. C. , Sitton G. M.
Published: December 2007

Steam displacement of oil in a slimtube under non-condensing isothermal conditions affords the opportunity to investigate two thermal mechanisms in relative isolation: steam oil displacement and steam distillation of oil in the dynamic situation. The added ability to investigate the composition of the produced oil under high resolution, allows estimation of a production allocation by mechanism. This work gives insights into strategies to accelerate the growth of the steamchest and enhanced compositional effects for improved steamflood performance.

The effects of temperature on oil and steam were determined in a sixty foot slimtube using Minas oil, a 33°API waxy oil from Indonesia, under isothermal conditions in the temperature range 300–600°F (149–315°C). Significant compositional changes in the hydrocarbon distribution of the produced oil allowed estimates that 16% of the oil is produced by vaporization alone in a light oil steamflood at 400°F (204°C). Higher temperatures increase the percentage for better vaporization and displacement recoveries. Steam can vaporize hydrocarbon components to at least C24 at 400°F (204°C) and much higher carbon numbers at higher temperatures. After steam breakthrough, vaporization becomes a major recovery mechanism in a steamflood. The vaporized hydrocarbons are normally seen as condensate in the field.

The steam vaporization process, like the carbon dioxide vaporization, removes the lightest hydrocarbons first and in boiling point order. The long slimtube acts like a gas chromatograph column and allows the separation of the hydrocarbons to be observed once vaporization begins. This is not normally seen in the field because the condensate commingles with the oil as it travels through the reservoir to the producing well. Therefore, a light oil having many light hydrocarbon components would produce a lot of condensate and a heavy oil could produce considerably less. The implications of compositional changes will be discussed.
The Extraction of Hydrocarbons from Crude Oil by High Pressure CO2
Authors: Siagian Ucok W.R. , Grigg Reid B.
Published: December 2007

This paper presents the results of a laboratory study investigation the capacity of CO2 to extract hydrocarbons from crude oils. The effects of pressure, temperature and oil composition on the extinction capacity of CO2 were studied. Extraction experiments using CO2 with Sulimar Queen stock tank oil and Spraberry sepetor oil samples at pressures between 1000 and 1900 psig were performed each at 95 F and 138 F. The experiments were performed by continuously injecting CO2 through 500-cc of oil placed in a 1.15 liter extraction vessel while continuously producing the upper or CO2 phase which contains the extraction products.

CO2 extraction capacity was found to be a strong function of pressure and temperature. The extract ion capacity increases with increasing pressure and decreases with increasing temperature. For the oils used in this study, the presence of solution gas in the oil does not affect the CO2 extraction capacity.

A CO2-Sulimar Queen oil extraction experiment at constant pressure and temperature of 1200 psig and 95 F, respectively, was performed for an extended period of time to determine the maximium oil recovery that can be achieved by CO2 extraction. It was found from the experiment that CO2 could recover at least 70 vol % or 64 wt % of the original oil in place. The CO2 extraction capacity decreased from around 0.3 g oil/g CO2 injected at the beginning of the extraction to 0.005 g oil/g CO2 injected at the time of termination.

Comparison of the extraction and slim tube tests results shows that the slim tube minimum miscibility pressures (MMPs) are near the pressure range at which a drastic increase in CO2-oil extraction rate occurs, which implies that CO2 extraction is a major factor in CO2-oil miscibility development. The comparison also shows that the extraction experiment appears to have promise as a good CO2-oil MMP estimation method.

P. 325
Engineering the Use of Green Plants to Reduce Produced Water Disposal Volume
Authors: Settle Troy , Mollock Gerald N. , Hinchman Ray , Negri M. Cristina
Published: December 2007

In 1990, the Laboratory began an investigation into biological approaches for the reduction of water produced from oil and gas wells. In the spring of 1995, the Company began an on-site experiment at an oil/gas lease in Oklahoma using one of these approaches. The process, known as phytoremediation, utilizes the ability of certain salt tolerant plants to draw the produced water through their roots, transpire the water from their leaves, and thereby reduce overall water disposal volumes and costs.

At the Company experimental site, produced water flows through a through where green plants (primarily cordgrass) have been planted in pea gravel. The produced water is drawn into the plant through its roots, evapotranspirates and deposits a salt residue on the plant leaves. The plant leaves are then harvested and used by a local rancher as cattle feed. The produced water is tested to assure it contains nothing harmful to cattle. In 1996, the Company set up another trough to compare evaporation rates using plants versus using an open container without plants. Data taken during all four seasons (water flow rate, temperature, pH, and conductivity) have shown that using plants to evapotranspirate produced water is safe, more cost effective than traditional methods and is environmentally sound.

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