bluuebunny/crossref_metadata_2025 huggingface dataset:
Characteristics and Impact of Asphaltene Precipitation During CO2 Injection in Sandstone and Carbonate Cores: An Investigative Analysis Through Laboratory Tests and Compositional Simulation
Authors: Takahashi Satoru , Hayashi Yoshihisa , Takahashi Shunya , Yazawa Nintoku , Sarma Hemanta
Published: December 2007

Characteristics and impact of asphaltene precipitation during CO2 injection are investigated for a Middle East crude oil in both sandstone and carbonate cores through phase behavior studies, corefloods and analyses of the deposition process using a compositional simulator. In phase behavior studies, a light-scattering technique with near infrared was used to determine the onset pressure of asphaltene precipitation. Also investigated were the effects of CO2 concentration on precipitation, including the potential for precipitation by CO2 at the current reservoir pressure.

The coreflood tests were conducted above the minimum miscibility pressure (MMP) in both carbonate and sandstone cores to investigate any difference in asphaltene precipitation characteristics in them. The asphaltene content in the produced oil decreased after the CO2 breakthrough –- an indication of its precipitation within the core. A careful post-test analysis of the flooded cores revealed that a larger amount of asphaltene was left behind in carbonate cores than sandstone core.

A compositional simulation study with tuned EoS parameters was carried out to evaluate coreflood results, followed by a parametric sensitivity analysis. In addition, the effects of rock heterogeneities on the oil recovery and asphaltene precipitation were investigated. A good match with the oil recovery was obtained. Results indicate that higher the degree of heterogeneities, the higher is the asphaltene accumulation in the core.
Field Application of a New In-Depth Waterflood Conformance Improvement Tool
Authors: Pritchett James , Frampton Harry , Brinkman Joe , Cheung Steve , Morgan Jim , Chang K. T. , Williams Dennis , Goodgame James
Published: December 2007

An Industry Consortium (BP, ChevronTexaco and Ondeo Nalco Energy Services) conducted a multi-company research project known as Bright Water. The goal of this project was to develop a time-delayed, highly expandable material that would improve the sweep efficiency of a water flood.

In November 2001, the first of these water flood profile modification treatments was pumped in the Minas field. The Minas Field, located on the island of Sumatra in Indonesia, has an OOIP of 8.7 billion barrels, is at nearly 50% recovery, and has water-cuts greater than 97%. Reservoir thief zones have been identified throughout the main reservoir layers. The main objective for pumping a profile modification material is usually to divert injected water out of thief zones and into zones with higher oil saturation, though areal sweep improvement can also be expected.

The profile modification treatment of 42,000 barrels water containing 4500 ppm of active material was pumped into Minas injector 7E-12 ("A1" sand). The objective of the field trial was to verify that significant volumes of this low cost material could be pumped deep into the reservoir at low viscosity, and then expand after a pre-designed time interval. Injection tracer studies were conducted pre- and post-treatment to aid in determining changes to the injection sweep efficiency. A bottom hole pressure fall off test was also used to measure post – job permeability.

The trial demonstrated that large volumes of the material can be pumped into the formation without raising the injection pressure or blocking the injection well bore, can propagate in the rock pore system, and then will expand at a pre-designed time. Changes in oil production after the trial will be discussed along with the field data acquired during and after the trial.

As part of the continued development of this material, a second trial commenced in late November 2002 on a North Sea (UK) production platform. The treatment was successfully placed in mid December, 2002.
Assessment of Three-Phase Relative Permeability Models Using Laboratory Hysteresis Data
Authors: Element D. J. , Masters J. H. K. , Sargent N. C. , Jayasekera A. J. , Goodyear S. G.
Published: December 2007

Gas injection techniques, such as WAG, frequently require consideration of co-existing oil, gas and water phases and the impact of saturation cycles as water and gas slugs move through the reservoir. These processes may be assessed using numerical simulations. This paper presents the analysis of a detailed laboratory study, designed to provide data for verifying hysteresis models for such simulations.

A number of studies have reported evidence for hysteresis in gas relative permeabilities in WAG flooding, leading to lower gas mobilities than predicted by conventional two-phase models. A reduction in gas mobility tends to improve gas sweep and incremental recovery for WAG based IOR schemes.

Three-phase hysteresis models have recently been developed to include these hysteresis effects. The models include trapping of gas and reduction of water relative permeability in the presence of trapped gas. In these models, saturation changes can be irreversible, and relative permeability may decrease with each change in direction in saturation.

A carefully planned laboratory study investigated secondary and tertiary immiscible WAG floods in both water-wet and intermediate-wet Berea cores, giving four separate sets of experimental data (a total of over 30 individual floods). For each flood, in-situ saturation profiles, mass balance and pressure drop data were measured. The in-situ saturation data ensures that laboratory artefacts (such as capillary end effects) do not influence conclusions.

Analysis of the experimental data shows that hysteresis models should include the following features: –Irreversibility of hysteresis cycles;–Potential for the reduction in the residual oil saturation with trapping of gas by water;–Reduction in both water and gas permeability, with potential for the fractional flow to vary with trapped gas saturation;–Variation in Land trapping factor between hysteresis cycles.

This study confirms the need for three-phase hysteresis models. Although published models may include some of the observed hysteresis effects, no model includes them all.
Field Application of HCl-Formic Acid System to Acid Fracture Deep Gas Wells Completed with Super Cr-13 Tubing in Saudi Arabia
Authors: Nasr-El-Din H. A. , Driweesh S. M. , Muntasheri G. A.
Published: December 2007

This paper describes optimization of gelled and in-situ gelled HCl/formic acid systems to stimulate deep gas wells completed with super Cr-13 tubing. High temperatures encountered in deep wells and the susceptibility of super Cr-13 to severe corrosion by concentrated HCl solutions and high chloride ion concentrations render acid stimulation a very difficult task. Therefore, extensive experimental and field studies were performed to develop a cost effective acid system to enhance the productivity of deep gas wells, while maintaining the integrity of the super Cr-13 tubing.

Coreflood tests indicated that this acid system can create deep wormholes in tight reservoir cores (less than 1 md). Corrosion tests, however, indicated that protecting super Cr-13 tubulars during pumping this acid (15 wt% HCl/9 wt% formic acid) is not an easy task, especially at downhole temperatures (275°F). A very limited number of inhibitor aids were found to be effective in protecting super Cr-13 at reservoir conditions. To optimize the corrosion inhibitor package, the bottom hole temperature was measured in a few wells during acid injection.

Based on lab tests and field measurements, an acid treatment was designed and applied in the field. The treated wells responded positively to the treatment. Most importantly, the integrity of the super Cr-13 was maintained. This was confirmed from chemical analysis of well flowback samples following the treatment and measurement of the tubing inside diameter before and after the treatment. The maximum Cr concentration in the flowback sample was less than 2 mg/L. Molybdenum and nickel concentrations were less than 1 mg/L. The total iron concentration was less than 200 mg/L. This value is significantly less than that noted with wells completed with low-carbon steel tubulars.
Drilling Demanding 16" Hole Section in Deep Gas Fields, Saudi Arabia: Challenges and Advances
Authors: Alkhamees Shaker , Klink Zeinoun , Isbell Matt , Ivers Chris , Scott Dan , Nawfal Nick
Published: December 2007

Drilling the 16" hole section in Saudi Arabia's Deep Gas fields is particularly challenging due to a complex stratigraphic section that consists of carbonates interbedded with tough bands of hard stringers in addition to an abrasive sandstone followed by dense dolomite. The operator has attempted to efficiently drill the section using both roller cone tungsten carbide insert (TCI) and polycrystalline diamond compact (PDC) technology. The roller cone TCI bits had unacceptably low rates of penetration (ROP) with short bit life that required multiple runs to finish the required section. PDC technology delivered acceptable penetration rates but inconsistent run lengths due to impact damage from vibration induced by either the bit, bottom hole assembly (BHA) or formation change. The operator evaluated several PDC designs from different manufacturers but all suffered similar problems including short bit life due to impact damage.

The operator determined to efficiently drill the section in one run and meet performance requirements would require new PDC/BHA technology. They organized a cross functional team to aggressively seek new PDC/BHA technology and state of the art motors and drilling practices to drill the interbedded rock section in one run. The team analyzed drilling operations from virtually every perspective using numerical models in addition to laboratory and field tests. The team identified PDC damage from BHA/bit whirl and vibration problems as the primary obstacle to achieving performance goals and focused their work on vibration management. The team performed BHA modeling analysis in order to develop a PDC solution that would minimize lateral and torsional vibrations. The modeling also helped determine the optimal range of operating parameters in order to meet performance requirements and eliminate BHA/bit whirl. The system solution combined high-power positive displacement motor to drive the bit harder and advances in PDC technology including improved bit stability and new cutter technology.

Due to the collaborative effort, the operator completed the demanding 16" hole section for the first time in one run using the new BHA/PDC bit combination. The application of this new technology has reduced cost/foot from $195.84 to $121.59 for a total saving of $365,681 over 4,925 ft and 226 drilling hours. The average section ROP went up from 14 ft/hr to 21.8 ft/hr, a 55% increase in ROP resulting in 38% reduction in drilling cost.
Experience with Rotary Steerable Systems in Onshore Abu Dhabi Fields
Authors: Al-Suwaidi Abdullah , Allen Frank , Taylor Randolph , Hussein Khalid , Russell Richard
Published: December 2007

The Abu Dhabi Company for Onshore Oil Operations (ADCO) operates a number of onshore fields in the emirate of Abu Dhabi in the United Arab Emirates. ADCO is a performance driven organization. As part of its Well Delivery Limit initiative, the company has focused on the technology enablers, and rotary steerables were seen to be one of the key technologies in delivering performance improvement.

The majority of the wells drilled in ADCO's fields include a horizontal lateral section through the reservoir. Therefore most wells require directional drilling technology and, in the past, have been drilled with conventional steerable mud motor assemblies. Due to the nature of the formations through the build and tangent sections and in order to provide directional control in the laterals, considerable orientated drilling has been required. Oriented drilling has proved to be time consuming and would often result in poor borehole quality. In order to minimize the effect of these issues and to optimize the overall drilling process, various types of rotary steerable systems have been used in a number of wells over the past year.

This paper will review the use of one of these systems. It is based on ‘point-the-bit’ and extended-gauge bit technology. The principle of the tool's design and its operational features will be discussed. In addition, selected case histories from ADCO wells will demonstrate the tool's ability to kick-off from vertical, build a smooth curve through the normally troublesome massive Nar Umhr shale sequence, and then geosteer through the horizontal section. Improvements in overall hole quality, and the benefits this brings, will be described.
A Safe Approach to Drilling Underbalanced Starts with Project Management
Authors: Williams Murray , Lewis Derrick , Bernard C. J.
Published: December 2007

This paper will examine the management issues, safety concerns of planning and executing a high end underbalanced drilling project. The discussion will include general safety, training, equipment, and conclusions.

Underbalanced drilling is inherently more dangerous than conventional drilling but the danger is mitigated by proficient project management, specifically, planning, training and the operational procedures followed during execution. Statistically, underbalanced drilling is still a very small percentage of worldwide drilling operations. This trend is changing as this disruptive technology is becoming more and more accepted throughout the industry. Our biggest challenge in the future will be to ensure that the past history of no major incidents or accidents attributed to Underbalanced drilling continues.

The planning that goes into an underbalanced drilling operation is more extensive than the planning of a conventionally drilled well. Some of the tools used in the planning phase of underbalanced operations include hazard identification (HAZID), hazard and operability (HAZOP), detailed operational procedures, and drawings such as equipment layout drawings (ELD), process flow diagram (PFD), valve numbering diagram (VND) and a hazardous area drawing (HAD). These processes contribute considerably to reducing the time and cost of engineering the underbalanced drilling program.
Fully Three-Dimensional Well Design Improves Margins in Critical Wells
Authors: Aasen Jan A. , Aadnøy Bernt S.
Published: December 2007

With the evolution of long, deep and hot wells, the design margins have become very small. This motivated the presented study and prompted the investigation for a precise well design model for burst and collapse. Although most well designs are based on one- and two-dimensional mechanics, more recent design packages include a three-dimensional version as well. It will be shown that these models are accurate only for certain conditions.

This paper presents an exact solution to the three-dimensional well design problem. Field examples demonstrate the accuracy of the new and conventional design models. The new model calculates design factors that are exact, thereby offering a tool for optimized well design. The presented theory is based on the von Mises yield criterion and the Lamé thick-walled solution for the pipe.
Challenges and Achievements of Drilling Maximum Reservoir Contact (MRC) Wells in Shaybah Field
Authors: Dossary A. S. , Mahgoub A. A.
Published: December 2007

Saudi Aramco's drilling strategy witnessed a change in year 2002 from drilling horizontal wells to more challenging and extended reach maximum reservoir contact (MRC) wells in Shaybah field. The objectives behind this change were to achieve the following: Improve the well productivity by providing maximum reservoir contact, reduce the unit cost of drilling ($/ft) and production ($/bbl), and to utilize the limited space more efficiently in the Sabkhah (flat areas between huge sand dunes). Different types of MRC wells were drilled, such as fork and fishbone in both open hole and cased hole to allow installing of intelligent completion packers for controlling the rate of production from each lateral. The reason for drilling different types of wells is to evaluate the impact of a well's type on the performance of the reservoir. The longest reservoir exposure ever drilled in Saudi Aramco was achieved by combining between the fork and fishbone in one well reaching up to 12.3 km (7.6 miles). Up to April 2003, eight MRC wells of different types and with 67.4 km (41.9 miles) of reservoir exposure were drilled in Shaybah field.
Real-time Decision-making for Value Creation while Drilling
Authors: Saputelli L. , Economides M. , Nikolaou M. , Kelessidis V.
Published: December 2007

Geological and operational uncertainties usually impair the ability of operators to achieve technical and economic goals of a drilling project. Use of real-time data integrated to the earth model has recently reduced the above uncertainties, thus improving project performance. However, the above solution has only addressed part of the overall problem of optimizing the well's economics, it cannot easily cope with the rapidly increasing amounts of data collected while drilling, and it has not been fully integrated with the control of operations yet. Therefore, we propose a multilayer and multiscale integrated strategy for decision-making while drilling and in well intervention and maximi. The proposed strategy aims to simultaneously optimize in Real-time the following four objectives (a) operational drilling performance, (b) initial well completion design, (c) well productivity and (d) value creation. By seeking to optimize an overall integrated objective rather than individual ones, the proposed strategy creates the possibility of achieving a solution that is superior to the aggregate of individually optimized solutions. In this paper we outline the strategy mentioned above and discuss recent applications that support our proposition.
Innovative Contracting Strategy Complements Technical Benefits of UBD in a Low Cost Environment
Authors: Francis P. A. , Murphy D. J. , Khan S. , Culen M. S.
Published: December 2007

For many years underbalanced drilling technology has been commercially exploited in North America whilst international Underbalanced Drilling (UBD) projects have been sporadic at best. Many technical papers have been written regarding these operations with the recurring theme that although the technical benefits of UB technology were seen, the overall cost was too prohibitive to justify further campaigns.

The many benefits of UBD are widely publicized; however, the highest impact that UBD can make is on the reservoir and its productivity. A recent focus in UB operations has been to quantify this benefit through productivity increase comparisons, or productivity improvement factors (PIFs) against field averages. The increased PIFs provide justification to offset the higher costs associated with the technology.

Petroleum Development Oman (PDO) has undertaken an extensive UBD campaign aimed at increasing production through the elimination of reservoir damage1. To fully evaluate the technology, the PIFs of a one year campaign were analysed and measured against a pre-defined business case to determine if UBD were commercially viable. The UBD campaign was carried out in two fields in PDO. Although this paper focuses on the Saih Rawl campaign, the issues for the two fields were very similar.

Although early production results were very promising2, the commerciality, in PDO's low cost, land operation environment, was marginal at best. Re-assessment of the approach to all aspects of the UBD operation by the Project Team, including scope of work, equipment design, equipment utilization and UBD operations resulted in improved operational efficiency and an innovative contracting strategy mutually beneficial to both Operator and Contractor. This new approach has shifted UBD from a trial to a commercially viable technology in PDO.
New PDC Technology Solves Challenging Directional Application in Saudi Arabia
Authors: Al-Hajji Ali , Klink Zeinoun , Khan Salahuddin , Isbell Matt
Published: December 2007

Directionally drilling the 8-V" hole section in specific areas of Saudi Arabia is particularly challenging due to a complex stratigraphic section that consists of soft, dense limestone and anhydrite with tough bands of hard stringers. Historically, roller cone bits with tungsten carbide inserts (TCI) have dominated the 8-1/2" application due to proficient steerability and ability to consistently achieve the required build rates in the soft limestone. However, multiple runs are required to finish the entire section. Conversely, Polycrystalline Diamond Compact (PDC) technology increased ROP but lacked consistency due to fluctuations in reactive torque that resulted in poor tool face control and inconsistent build-up rates relative to roller cone bits.

Saudi Aramco determined to efficiently drill the section in one run and meet performance and directional requirements would require new PDC technology. To address this challenge, Saudi Aramco and a service company organized an integrated cross-functional team composed of engineers from both companies to aggressively seek new steerable PDC technology to drill the curved section with controllable torque response and consistent directional behavior while achieving the full penetration rate advantages of PDC bits.

The team analyzed the drilling operation from virtually every perspective using numerical models, laboratory drilling tests, and field testing. The key to the PDC solution was the team process that identified the relevant drilling problems and performance requirements in order to develop the needed technology.

The team identified that poor tool face control in the soft limestone and cutter damage due to vibration problems were the primary obstacles in achieving performance goals. The solution was a PDC design with a new steerable concept that provided exceptional tool face control without sacrificing ROP in addition to improved stability and new cutter technology for prolonged bit life.

After 15 bit runs, the team reduced drilling cost by $17.55 per foot for a total savings of $857,476 over 48,871 ft and 1880.5 drilling hours. The average ROP for the section increased from 22.47 ft/hr with standard PDC bits to 26 ft/hr with the new PDC technology. The current ROP record stands at 42.02 ft/hr with the single run record footage standing at 6,229 ft.
Novel Drilling, Completion and Workover Fluids for Depleted Zones: Avoiding Losses, Formation Damage and Stuck Pipe
Authors: Reid P. , Santos H.
Published: December 2007

As oil and gas fields become mature, there is an increasing need to drill, complete and workover wells in depleted zones. The proximity of normally pressured zones often means that, in order to maintain wellbore stability, the depleted formations experience very high overbalance pressures – often exceeding 1000psi. As a consequence, problems such as differential sticking, deep filtrate invasion and severe lost circulation are common. In the extreme, increased costs and high levels of formation damage can make continued exploitation of fields uneconomic.

This paper describes a new fluid additive package designed to form an effective, low permeability barrier on permeable formations. The materials have been used in a wide range of water, oil and synthetic based fluids with excellent results. We present laboratory evidence and field data to show that fluid invasion is greatly reduced. This brings several important benefits: Differential sticking is greatly reducedFracture gradients are increased (increases well over 1000psi have been observed).Return permeability results, and hence well productivity indications, have been excellent.

The paper discusses the mechanism by which the additives provide superior invasion control, and the ease with which the protective barrier is removed from producing intervals.

The materials have been used onshore and offshore in most major oil and gas provinces. In addition to providing effective technical solutions, they have the environmental approvals that allow their unrestricted use in areas such as the Gulf of Mexico and the UK North Sea.
Successful Water Based Drilling Fluid Design for Optimizing Hole Cleaning and Hole Stability
Authors: Kjøsnes I. , Løklingholm G. , Saasen A. , Syrstad S. O. , Agle A. , Solvang K. -A.
Published: December 2007

Water based drilling fluids have been used in many North Sea drilling operations during the last decades. Traditionally, a high focus has been directed towards creating inhibitive drilling fluids with high low shear rate viscosity for optimising cuttings transport and intact cuttings on the shaker. It has, however, been recognized that there is no direct connection between cuttings quality and hole stability. In the current field it was also found that a low gel/viscosity drilling fluid is effective in transporting cuttings out of the wellbore. Following this, the content of high molecular weight polymers have been reduced and exchanged with low molecular weight polymers to enhance hole cleaning throughout the last years. Fewer cuttings are entrapped in beds down hole and are transported up to the surface. The current paper demonstrates how this low viscous/low gel strength drilling fluid contributed to improved drilling performance, where an improvement in tripping time, casing running speeds and total drilling time was observed.

In addition to changes in the viscosity a wide range in NaCl and KCl salt concentrations and mixtures have been tried and field tested. The project is currently using only a moderate concentration of KCl, which has improved hole stability. The frequency of unstable hole occurrences in a particular troublesome formation are today greatly reduced by using lower KCl salt concentration and improved well design.

The current paper explains in detail how the drilling fluid design optimizes the chemical performance and the hole cleaning performance during the drilling operation. The drilling performance for this particular field improved significantly during the last three years where the total drilling time was reduced with roughly 50% compared to earlier practice. The reasons for the improvements are mainly the changes in well design combined with the use of an effective WBM system.
Cantilever Drilling — Ushering a New Genre of Drilling
Authors: Sinha Diwakar
Published: December 2007

Cantilever drilling is a new concept of drilling which will enable us to drill superwide boreholes with radii of the order of a few feet selectively in zones of our choice. This enlarged hole will facilitate better artificial lift and enhance production among other things.
Optimum Wellbore Cleanup of Drilling-fluids Enhanced by Drill-string Rotation, Reciprocation and Detergents
Authors: Nwoke Linus , Uchendu Chike , Arukhe James , Mamman Ajee
Published: December 2007

Drilling-fluids cleanup of casing is achieved by either turbulent flow, contact time, rotation or reciprocation across the casing waif, but combination of all gives excellent result.

The paper presents an enhanced casing welfbore cleanup methodology of combining detergents, drill-string rotation and reciprocation to clean casing and achieve a solids­ free completion fluid of less than 30NTU's (Nephelometric Turbidity Units). The method has successfully in some field applications displaced and cleaned up wells completion fluid NTU levels of less than 20 NTUs within some 2 hours of pumping time.

Cleanup was carried out in one phase as the chemical-pi/1-train is formulated to be capable of displacing the mud and cleaning the wellbore simultaneously. A one-trip consideration was given for provision of adequate spaces for the backload of mud and the containment of contaminated fluids. A one-trip phase, with rotation and reciprocation was combined with scraper-run and displacement of welfbore to creek or industrial water, thereby saving considerable rig-time. An engineered pumping design generated the required rates and turbulent flow necessary to optimally clean-up the casing.

This paper presents the successful cleanout of drilling mud in five trial wells in a Niger Delta field (referred to as Niger field).
Design, Installation, and Results from the World's Longest Deep-Water Openhole, Shunt-Tube Gravel-Pack West of Shetlands
Authors: Wilson Allan , Roy Alistair , Twynam Allan , Shirmboh Daniel Ndzi , Sinclair Garry
Published: December 2007

A large majority of the wells in deep-water/subsea environments are being drilled as horizontal wells to gain cost-effective accessibility to multiple sand bodies and larger reserves. Most of these wells are being completed as open holes because of the higher productivities as well as lower costs associated with such completions. Furthermore, a substantial fraction of the fields in deep-water environments requires some sort of sand control. Although standalone screen completions have been used successfully in some of these deep-water fields (relatively large sand grains and uniform particle size distributions, with little to no fines), premature sanding problems have been reported, jeopardising project economics as a result of prohibitively high cost of remediation.

In this paper, we present a significant case history on the application of the simultaneous gravel-packing and cake-cleanup technique in the Foinaven field, West of Shetland, UKCS. The well is the first gravel-pack completion in this deep-water, harsh environment, where various types of standalone screen completions have been utilised since the initial development of the field in 1994. The subject well is of 3,075-ft open hole, penetrating through two sand bodies separated by a 530-ft shale section. It is the first openhole gravel-pack completion in such an environment in the North Sea to result in 100% packing efficiency based on gauge hole calculations and a zero mechanical skin based on pressure build-up testing.

In addition to being the first horizontal well West of Shetland to be drilled with water-based mud (WBM), this was the first production well to be drilled in a new reservoir horizon of the field, discovered and brought on line in less than 10 months. Initial production from the well far exceeded expectations and the completion was delivered safely and 3 days ahead of the target time.
Application and Study of Fine-Silty Sand Control Technique for Unconsolidation Quaternary Sand Gas Reservoir, Sebei Qinghai
Authors: Zhou Fujian , Yang Xianyou , Xiong Chunming , Zhang Shouliang , Zong Yiping , Sun Lingyun , Guan Ziqiang
Published: December 2007

Sebei Gas Field is located in the northeast of Caidam Basin, Qinghai, China. Its main pay-zone is unconsolidation Quaternary fine-silty and dirty sandstones with serious sand production. Grain size of the sand is very fine, about 0.04-0.07mm, so sand control is very difficult. In past ten years, many sand control methods (such as mechanical, chemical and frac-pack sand control) have been applied; however, expectant effect had not been achieved. Condisering the conditions of Sebai Gas Field, we succeed in applying a series of technique of comprehensive sand control with fiber-resin coated sand. The technique adopts formation pretreatment, clear brine-based VES (viscoelastic surfactant) fracture fluid as sand carrier, special glass fibers and resin-coated sand complex for fracture pack stabilization and enhanced proppant transport, frac-pack and TSO (tip screen out) for increasing productivity, bypassing near well bore damage, interconnecting multiple sandstone layers and decreasing fluid velocities in the formation to reduce fines production. This combined rehabilitation technique enabled screenless sand control completion, allowing low cost rehabilitation of plugged or failed sand screens and the development of any numbers of gas layers which otherwise could not be drained with conventional sand control technologies.

The technique was exercised in well Se 3-18; the results proved to be remarkable. Before sand control, serious sand production begins at 4.5×104m3; after sand control, sand production cannot be found at 91200 m3/d. Up to now, the well has been produced for nearly one year with stable gas production at 10×104m3 and no more sand production. This paper presents lab study, operation design, field operation and result analysis about the sand control technique.
A Successful Scale Removal Operation by Use of New and Old Technology
Authors: Børeng Raymond , Skinnemoen Odd Kåre , Vigen Arild , Vikane Olav , Andrews Jamie , Larsen Ragnar , Hauptmann Thore
Published: December 2007

The Statfjord oil field, operated by Statoil in the North Sea, is far down its production decline curve. 60% of the STOOIP has been recovered during the past 23 years of production with secondary recovery techniques, leaving complex distributions of by-passed oil reserves, water and gas.

In order to maintain cost-effective production of the remaining reserves, an aggressive drilling and intervention programme is necessary. Future field development might also include a pressure blow down of the reservoir. So far the Statfjord Field has exhibited a fairly mild scale potential. Sulphate scale has been detected in several wells downhole; in the near well bore area, in the perforation tunnels or in the well bore. Well bore accumulation has been observed both as a thin layer along the tubing or as massive build up in the wire-line re-entry guide. Carbonate scale, when present, is mainly observed above the wireline retrievable downhole safety valve (DHSV). Statfjord wells are typically completed with wire-line retrievable downhole safety valves, which are function tested every 6 months. In wells prone to scaling this testing frequency is increased to 3-months.

In well C-36 scale build up had been confirmed in the 5 1/2" re-entry guide during production logging in June 1998. Following deterioration in well performance, a successful scale dissolver and inhibitor squeeze was performed early in 1999. Later in 2001 the DHSV failed, but this was corrected by an acid job. However, the safety valve failed again in June 2002 and proved this time to be immune to acid treatment and the well had to be shut in. The well condition was evaluated by running gauge rings into the well and this showed extensive scale build up over the DHSV. New and old technologies were evaluated for scale removal.

Statfjord has had good experience of scale removal with Coiled Tubing (CT) milling. This approach would probably have been successful in well C-36 but, due to long delivery time and the cost of deferred oil production, a wire-line solution was sought. An operation program was designed for mechanical removal of scale with wire-line (WL) broaches in combination with a stiff wire-line brush. Wire-line tractor (WLT) milling and string shots were included as back up options.

As the operation proceeded it became evident that mechanical broaching and backup WLT-milling were inefficient at removing the hard Ba/SrSO4 scale. However, use of explosives on string-shot runs was successful in removing the scale and getting the well back in production. In order to evaluate the scale removal process a multi finger caliper (MFC) was run several times during the operation. The MFC showed a scale layer with variable scale thickness up to a maximum of 1".

A successful scale-removing job was performed and the well came on stream with approximately 700-1000 Sm3/d of oil after the operation. A CT milling operation was avoided.
Application of New Fracturing Technique Improves Stimulation Success for Openhole Horizontal Completions
Authors: East Loyd , Willett Ron , Surjaatmadja Jim , McDaniel B. W.
Published: December 2007

Proposal

A relatively new technique for applying fractures (both proppant fracs and acid fracs)1–3 in horizontal openhole and uncemented liner completions is giving operators a more effective method for stimulation of underachieving wells. The process incorporates the known technologies of hydrajetting and fracturing in a novel way to achieve individual fracture placement at several selected locations along the lateral without the need for mechanical isolation methods, usually with only one service trip to the location. Depending on the number of fracturing stages desired, most job times vary from 6 to 12 hr if there are no hole-entry, tool, or logistic problems.

Use of this new stimulation process continues to expand in the USA and Canada, and during the fourth quarter of 2002 and the first half of 2003, application of this process was successfully expanded beyond these original development areas to include offshore South America and a region of northern Asia. Before the end of 2003, numerous other locations around the globe are also planning to implement this stimulation technology on underperforming horizontal completions.

Although this stimulation technique can also be used for cemented liners, its unique ability to control fracture placement in openhole and uncemented liner applications will be the focus of this paper. Only a brief review the basic technology is presented here, as numerous earlier publications provide more detail. New case histories will be presented wherein the application of this process has provided the operator with a distinct improvement in well completion economics.
Fracture Treatment Design and Execution in Low Porosity Chalk Reservoirs
Authors: Cipolla C. L. , Hansen K. K. , Ginty W. R.
Published: December 2007

Proposal

This paper details the results for 33 propped fracture treatments in low porosity zones in the South Arne field, Danish North Sea. To date, seven horizontal wells (2900 m TVD) have been completed using 100 tip screen-out (TSO) propped fracture treatments containing 70 million pounds of proppant. The target oil bearing Tor & Ekofisk intervals range from 40m to 120m of combined thickness, with a Young's modulus and permeability that can vary from less than 0.5 MMpsi to over 2.5 MMpsi and 0.1 to 4 mD, respectively, along the horizontal section. The wide variations in reservoir and rock properties presents significant fracture design and execution challanges.

Results indicate that propped fracture treatments become increasingly more difficult to place as porosity decreases and this problem is primarily attributed to higher natural fracture/fissure density in the lower porosity, higher modulus zones. Production data indicate that these natural fractures or fissures do not measurably contribute to productivity, but can be "activated" under fracturing conditions. Counter intuitive, pad size and fluid loss additives must be increased and maximum proppant concentration decreased in low porosity (low permeability) zones. In the higher porosity, higher permeability northern portion of the field, pad sizes of 35,000 gals containing 20,000 lbs of 100-mesh sand allowed the placement of 800,000 lbs of proppant at concentrations up to 15 ppa. However, in the lower porosity, lower permeability southern portion of the field, pad sizes of 200,000 gal containing over 100,000 lbs of 100-mesh sand were required to place similar proppant volumes, with concentrations limited to 8 ppa. This paper summarizes field data from 100 treatments, illustrating the design changes necessary to place propped fracture treatments in low porosity chalk reservoirs. The paper documents the relationship between chalk porosity, fluid efficiency, and treatment design.
Interpretation of Field Experiments and Observation of Fracturing Process
Authors: Daneshy Ali , Blümling Peter , Marschall Paul , Zuidema Piet
Published: December 2007

Proposal

Detailed experiments were performed in four instrumented boreholes to determine the growth pattern of an induced hydraulic fracture and its impact on flow through an ultra low permeability formation. The instrumentation allowed measurement of fracture pressure and width in three boreholes which were intersected by a fracture induced from a central well. The fracturing fluid was synthetic pore water to prevent formation damage.

The experiments showed that because of the difference between the instantaneous fracture velocity and fluid velocity inside the fracture the fluid front lags behind fracture front. There was a large pressure drop along the length of the fracture which caused rapid narrowing of the fracture width, poor hydraulic communication along the fracture length, and localized growths and fluid movements.

The data confirmed an off-balance fracture growth pattern, consisting of tensile and shear fractures and many branches.

At the end of the treatment, even though the fracture contained some residual opening, it had very little conductivity along its length. At the same time, because of its off-balance growth the fracture had the capacity to transmit fluid locally and trap and hold part of the treatment fluid inside the ultra low permeability formation.

These experiments have raised new questions about some of our common assumptions in hydraulic fracturing. These include the pattern of fracture propagation, pressure distribution inside the fracture, fracture closure and re-opening, in-situ stress measurement, etc.
Radial Near Wellbore Stimulation by Acoustic Waves
Authors: van der Bas Fred , de Rouffignac Eric , Zuiderwijk Pedro , Wong Sau-Wai , van Batenburg Diederik , Birchak Bob , Yoo Kwang
Published: December 2007

Production of oil and gas wells is often reduced due to damage in the near-wellbore region related to the drilling process. In many instances, the damage is caused by the interaction of the reservoir formation with drilling and completion fluids. This damage can increase during the life-time of the well due to influx of formation damage (fines, scale, asphalthenes, etc). An example is formation fines plugging a slotted liner or screen.

High frequency sonic waves have been used in many industrial applications to remove contaminants like dirt, oil, and grease from parts immersed in fluids. An obvious extension of this application is the removal of wellbore impairment by exposing it to high frequency acoustic waves. Although the concept is old, successful large-scale application of acoustic well stimulation is not yet common. During the last decade the manufacturing of high-power piezo-electrical elements developed fast and opened the potential to design a downhole acoustic cleaning tool.

The advantages of an acoustic cleaning tool is the selectivity of the treatment compared with conventional matrix acidizing treatment. Also the need for large quantities of chemicals (acid, corrosion inhibitor etc.) can be eliminated.

In previous publications the potential of acoustic cleaning has been reported using experimental results obtained in a laboratory set-up using linear acoustic waves. In this paper the results will be presented on the cleaning of mud damage using a prototype acoustic tool in a radial geometry.
Impact of Water-Based Polymer Fluid Characteristics on CO2 Foam Rheology
Authors: Fredd Christopher N. , Miller Matthew J. , Quintero Baudel W.
Published: December 2007

High performance foamed fracturing fluids are required to enhance cleanup during applications in low permeability, low pressure gas reservoirs and mature, depleted hydrocarbon reservoirs. Moreover, accurate foamed fluid rheological properties, obtained under field conditions, are necessary to enable complex fracturing treatments to be executed successfully. Standard laboratory tests used to evaluate properties of foamed fluids include the foam half-life measurement and the characterization of the water-based polymer fluid rheology that serves as the external aqueous phase of the foam. These tests are generally limited by the absence of CO2. In addition, the rheology tests are commonly performed with the pH of the water-based fluid adjusted with acid to a value consistent with that expected for CO2 foam under reservoir conditions.

This study evaluates the relevance of conventional laboratory tests in indicating the performance of CO2 foam fracturing fluids formulated with linear and zirconate crosslinked carboxymethylhydroxypropyl guar (CMHPG) polymer. Specifically, the effects of the water-based polymer fluid pH, crosslink delay and corresponding shear sensitivity, temperature, and foam quality are evaluated under typical conditions encountered in a fracture. Relatively new capabilities to measure pH in the presence on CO2 under high-pressure (up to 1,500 psig) and high-temperature (up to 280°F) indicate pH values in the range of 3.5 to 4.1 for CO2 foam under down hole conditions. Results demonstrate that the common practice of performing Model 50 rheology tests with water-based polymer fluids adjusted to low pH to simulate the effects of CO2 are not indicative of CO2 foam fluid performance, as the foam viscosity was not dependent on the crosslink delay or crosslink pH. Furthermore, standard shear history tests with zirconate-crosslinked CMHPG fluids did not correlate well with foam performance at qualities greater than 52% CO2. This work demonstrates the conditions under which CO2 foam rheology is dominated by foam properties versus water-based polymer fluid properties.
Optimizing Filtrate Design to Minimize In-Situ and Wellbore Damage to Water-Wet Reservoirs During Drill-In
Authors: Dalmazzone Christine , Audibert Annie , Quintero Lirio , Jones Tom , Dewattines Carine , Janssen Michel
Published: December 2007

A prominent area of concern related to drill-in and completion operations is damage caused by polymer and/or brine filtrate invasion into the producing formation. It is common knowledge within the petroleum industry that, in overbalanced conditions, filtrate invasion into the pore spaces of a reservoir is continuous as long as the drill-in fluid and wellbore are in contact. It is also commonly known that certain polymers and modified starch additives tend to adsorb or to be retained, and sometimes plug, the water-wet linings of reservoir pores. Once this occurs, flow paths are restricted and formation permeability is impaired. Despite the careful selection of less damaging polymeric viscosifiers and fluid loss agents, reduced mobility of production fluids remains a problem. Depending on the compatibility of the aqueous filtrate with the reservoir fluids, strong water/oil emulsions may be formed and also plug reservoir pores.

This paper presents credible laboratory data demonstrating the benefits of a special surfactant molecule engineered to pass through a drill-in fluid filter cake along with the other filtrate components to maximize wellbore productivity. Functionally, this chemistry (1) inhibits the adsorption of the drill-in and completion fluid polymers on the in-situ surface areas of the reservoir, (2) reduces the water saturation level of the formation rock to increase flow area, (3) promotes compatibility between the brine filtrate with formation crude, and (4) reduces the surface properties between filter cake particles to enhance the ease of wellbore clean up during displacement and natural cake "lift-off" during the onset of production.

Collectively, these benefits, when used to complement pre-established drill-in fluid design criteria, further increase reservoir productivity in open hole completion applications.
A New Industry Standard for Determining the pH in Oilfield Completion Brines
Authors: Prasek Bethicia B. , Freeman Michael A. , Carpenter Joel F. , Dalton Ferrill G. , Isaac D. Donald , Guy-Caffey Judith K. , Tomlin Marsha , Javora Paul , Jones Tom A. , Malachosky Ed
Published: December 2007

An API-sponsored work group has developed a robust field and laboratory method for determining the pH of oilfield completion brine. This method is precise, gives reliable pH values, is free from interferences, and can be easily implemented across industry. It is anticipated that this user-friendly method will be incorporated into the API Recommended Practice 13J: Testing of Heavy Brine.1