bluuebunny/crossref_metadata_2025 huggingface dataset:
Performance and Evaluation Methods of Colloidal Dispersion Gels in the Daqing Oil Field
Authors: Lu Xiangguo , Song Kaoping , Niu Jingang , Chen Fuming
Published: December 2007

Polymer flood has been being used to provide a valuable tool for in-depth blockage of high permeability regions of the reservoirs in the Daqing oil field, where more than fifty thousand tons of polymers had been injected into reservoir for each year. But heterogeneity inside the reservoir is very serious in some areas and has caused channlling of polymer solution through high permeable zones, which not only wasted a lot of polymer but also affected the volumetric sweep.

The colloidal dispersion gels (CDG) were made up of low concentrations of polymer, aluminum citrate and additive in water, and combined with polymer solution during polymer flood for in-depth blockage of high permeability regions1,2,3. This paper provides a study of the performances and characteristics of the gels that were made up of aluminum citrate, produced water and polymer made in the Daqing oil field. The parameters used to evaluate performances and characteristics of the gels in laboratory include resistance factor, residual resistance factor, viscosity, elasticity, and polymer molecular texture and flood efficiency. The experiment results showed that the cross-linking reaction among a few polymer molecules or inside a molecule had taken place, which caused performance difference between the gel and polymer solution, and the best gels can be formed with a polymer: aluminum: additive S ratio of 100: 1: 25. The cost of the gels formed with the above-mentioned ratio was below 5 dollars /m3, which was almost the same as polymer solutions. According to these experimental results, two pilot test units with seven injection wells have been selected in the central part of the oil field, in which there are three central injection wells.
Prediction of Fracture Gradients in Samaan Field
Authors: Parriag E.R.
Published: December 2007

This study was undertaken to develop a correlation curve to show the variation of fracture pressure gradient with depth in the Samaan Field Offshore Trinidad. The method used to predict the Samaan formation fracture gradients is that of Ben Eaton. The results indicate that Samaan fracture gradients vary from 0.6 psi/ft at 1000 feet to 0.99 psi/ft at 12,000 feet.

Introduction

Fracture pressure gradients are necessary in designing casing and mud programs and help to avoid lost circulation problems while drilling. Fracture gradient has been shown to be a function of three independent variables, namely formation pore-pressure, overburden stress gradient and Poisson's ratio. In this study, each of the above three variables has been determined for the Samaan area and the resulting fracture pressure gradient curve has been constructed. pressure gradient curve has been constructed.

Prediction Methods

Several studies have been carried out to arrive at a method of predicting formation fracture gradients. Hubbert and Willis in 1957 and Matthews and Kelly in 1967 published papers outlining two different methods of predicting fracture gradients. Ben Eaton in 1969 developed a method which is modification of the Hubbert and Willis approach.

Hubbert and Willis Method

Hubbert and Willis used the following equation to determine fracture gradient:

(1) D D D 1-u D Pw = ( S − P ) ( u ) + P

(A) (B) (C)

Term (A) is the effective stress gradient, (B) is the horizontal to vertical stress ratio and (C) is the formation pressure gradient. Hubbert and Willis assumed that the over-burden stress gradient S/D was equal to 1.0 psi/ft and Poisson's ratio (u) equal to 0.25. Substitution of these values in equation (1)results in the following:

(2) D PW = 1 3 ( 1+2P ) PW = 1 3 ( 1 + 2 P )

However, these assumptions of Hubbert and Willis have been shown to be in error in many areas.

Matthews and Kelly Method

Matthews and Kelly presented a fracture gradient equation similar to equation.

P. 59
Flexible Drilling Tool May Aid In Enhanced Oil Recovery
Authors: Gourley Gary
Published: December 2007

A new tool in the industry may offer hope in regaining production from wells hindered by skin damage. A flexible drill string known as the Flex Tool was designed to drill a new well bore from vertical in order to get beyond the immediate perimeter of the well bore into new virgin territory. It can be run directly on the end of a work over string, without a motor, drilling a new well bore away from a kick off point adjacent to the pay at a slant approximately 15 feet from the vertical well bore allowing a new hole possibly horizontal into the target formation. If formation potential exist in this new well bore now beyond shallow well bore damage, it could offer hope for increased or regained production.

With economics in mind, this tool was designed to drill a short radius curvature for an operator seeking affordable alternatives to work over solutions. The ability to obtain a horizontal hole by an affordable means affordable makes the benefit to cost ratio extremely promising in some cases. This definitely put this tool on the list for the new millennium. this country has many older wells in need of work over solution to maintaining or regain production potential. An adjacent slant or horizontal well bore may be a great solution to overcoming the problems of abandonment. An experimental job near Graham, Texas will be discussed.
Have we Forgotten Oil is not Inert? Guidelines for Enhancing Stimulation Success.
Authors: King S. R. , Worley H. W.
Published: December 2007

Data bases, computer modeling and lower job costs have become the focus of stimulation treatment design. This focus has directed the attention away from well specific fluid testing and formulations. Fluids and additives for non proppant applications are often assumed to have equal performance and are compared only for cost. The value of fracturing fluids is often based on rheological properties and viewed only as a means to transport proppant. This line of thinking ignores potentially serious compatibility consequences in oil reservoirs.

Oil is not inert. The compatibility of treating fluids can enhance or impede production. Cold fluids can precipitate damaging high melting point paraffin. Acid treatments without adequate iron control, surfactants and/or aromatic solvents will sludge some crudes. Diesel has been shown to precipitate asphaltenes in some circumstances. This paper discusses testing and evaluation methods beyond conventional emulsion testing for cost-effective performance enhancement. Guidelines for testing, evaluating and enhancing stimulation treatments are presented with case histories.
San Andres and Grayburg Imbibition Reservoirs
Authors: Jerry Lucia F.
Published: December 2007

Residual oil zones several hundred feet thick are found beneath many San Andres and Grayburg oil reservoirs in the Permian Basin, West Texas, suggesting that these reservoirs once contained a much larger oil volume. Oil has migrated out of these reservoirs, causing the oil-water contact and the zero capillary pressure level (zcpl) to rise, placing the reservoir in imbibition rather than drainage mode. Therefore, saturation profiles should be characterized by the imbibition capillary pressure curve. Imbibition curves have lower water saturations in the productive interval and significantly smaller transition zones than predicted by drainage curves. The reduction in the transition zone is a function of the rise of the zcpl, which is equal to the thickness of the residual oil zone. A more accurate estimate of original oil in place can be obtained if imbibition curves are used to model fluid saturations.
Improving Economics of Production in Heterogeneous Reservoirs by Redirecting Water Injection Patterns
Authors: Prasad Rajan K. , Lake Larry W. , Jennings James W. , Lucia F. Jerry
Published: December 2007

Heterogeneous reservoirs undergoing waterflooding contain low-permeability zones in which oil in the low-permeability zones is bypassed by water. Profitability of producing from heterogeneous reservoirs can be poor because of premature water-breakthrough through high-permeability layers. It seems possible to improve the profitability of producing from heterogeneous reservoirs by diverting the injected water from preferentially flowing through high to low-permeability zones. The profitability improves because of a small increase in ultimate oil recovery and/or a large reduction in cumulative water production. The objective of this study is to investigate the applicability of the technology, referred to as indirect waterflooding, in different types of heterogeneous reservoirs.

We performed numerical simulations of waterfloods on a generic five-spot pattern for three different reservoir cases. The reservoirs had properties typical of a San Andres Formation. The first case, with vertical-heterogeneity, showed that ultimate oil recovery might be improved by up to 13% OOIP with indirect waterflooding. The second case, with areal-heterogeneity and a low kv/kh, showed that water production might be reduced by as much as 27%. The third case, with areal heterogeneity and a zero kv/kh, showed that water production might be reduced by 31%. Actual recoveries are sensitive to reservoir properties, especially in the magnitude of the vertical permeability.
Precision Pressure Measurement: The Key to Accurate Fluid-Interface Monitoring
Authors: Hannah P. M. , Vekved K. L.
Published: December 2007

In highly fractured reservoirs, where gravity dominated recovery processes are employed, fluid contact measurements and isobaric mapping are useful tools for understanding operational and process changes. Monitoring fluid contacts accurately in highly fractured reservoirs has always posed a challenge due to limitations in the measurement tools. Gradiomanometer surveys and electronic fluid property surveys lack the depth resolution needed to locate contacts, and direct measurement methods are time consuming, messy and yield no secondary information for quality control. Fluid gradient measurement is the desired method; but historically, limitations in gauge precision or thermal response have made this method unattractive.

An electronic pressure gauge using a silicon crystal sensor was shown to provide predictable response to strain under changing temperature and to provide the precision and accuracy needed for repeatable contact measurements and reliable pressure mapping. The pure silicon crystal has a small mass, a thin unbonded structure, and a temperature sensor for compensation placed in close proximity thereby decreasing the stabilization time required for true pressure recording. Rapid pressure measurement allows shorter, more frequent gradient stops; and consequently better data resolution for contact calculations.

Replacing non-pressure based contact measurement techniques in a field where bottom hole pressure surveys were taken on staggered intervals saved real dollars. This was done by adding one to two days onto a pressure survey and eliminating the separate contact survey. Measuring both contacts and pressures concurrently reduced time-normalization problems and increased data confidence. Accurate, repeatable pressure measurements clarified details of operational changes on the reservoir management process, improved the data collection process, and reduced expenses to the operator.
Asphaltene Inhibitor Evaluation in CO2 Floods: Laboratory Study and Field Testing
Authors: Yin Y. Ralph , Yen Andrew T. , Asomaning Sam
Published: December 2007

CO2 miscible gas flooding is a popular method of improved oil recovery. It is widely used in the Permian Basin. Asphaltene deposition in many of these systems is a costly operational problem associated with the utilization of this method of recovery. A CO2 flood in West Texas was experiencing major problems with asphaltene deposition related ESP failures and tubing plugging.

Operational procedures, field experience and a successful chemical program have greatly reduced the cost of these problems over the last 3 years. A new inhibitor for continuous capillary injection was recently developed and performed well on live oil lab tests. To evaluate the field performance of this new asphaltene inhibitor, a wellhead side stream filter loop was constructed to monitor asphaltene precipitation/deposition. The objective was to measure and compare the time needed to plug a given size filter with untreated and chemical treated produced fluids. Pressure data at the filter loop and wellhead was also recorded to monitor the effectiveness of the treatments.

The field trial results proved the use of a filter-plugging side stream was an effective way of assessing asphaltene inhibitor performance. Based on the filter plugging and wellhead pressure data, it was concluded that asphaltene precipitation/deposition occurred if the produced fluid was not chemically treated. The standard field product used successfully in the past was able to reduce asphaltene deposition and doubled the filter plugging time. The new asphaltene inhibitor was shown to be more effective for stabilizing the asphaltenes in the CO2 flooded produced fluids. The new inhibitor extended the time needed to plug a filter by more than four times as compared to untreated fluids.

Case history information, laboratory tests results, side stream configuration, field test procedure and field test results are presented.
Cost Effective Removal of Iron Sulfide and Hydrogen Sulfide from Water Using Acrolein
Authors: Salma T.
Published: December 2007

Iron sulfide (FeS) and hydrogen sulfide (H2S) pose serious operational and safety problems in water injection systems. While H2S can cause corrosion and toxicity problems, the most common problems associated with iron sulfide are plugging of equipment, filters, injection lines and the formation face. Iron sulfide is frequently formed under oilfield conditions from the interaction of iron with hydrogen sulfide in produced water. Different forms of iron sulfide are produced as a result of both chemically and biologically mediated complex reactions. Furthermore these different forms of iron sulfide undergo various transformations as they are subjected to different environmental conditions. Acrolein acts on H2S and iron sulfide through an irreversible chemical reaction with the sulfide entity, producing nontoxic, water soluble, low molecular weight products. Acrolein is being used successfully in oilfield applications both land-based and offshore for removing H2S and iron sulfide from produced water. Acrolein treatments have been shown to be highly effective in terms of cost and performance. This paper presents field data on the performance of acrolein in mitigating iron sulfide and H2S problems in water injection systems and compares acrolein performance to that of other chemicals. The parameters monitored in the field to determine performance were frequency of injection filter replacement, water quality, and Millipore filtration times. Results from extended field tests demonstrated that acrolein was the most efficient and cost effective chemical of those tested in removing iron sulfide and hydrogen sulfide from the injection water system.
Unsteady-State Flow Behavior for a Well Near a Natural Fracture
Authors: Cinco L. Heber , Samaniego V. F. , Dominguez A. N.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A mathematical model was developed to study the transient flow behavior for a well near an infinite conductivity vertical, nonintersecting, natural fracture in an infinite slab reservoir. A slightly compressible fluid was considered. Results when plotted as a function of a dimensionless time follow at ear times a straight line of 1.151 slope characteristic of radial flow. After this radial flow period, the well pressure behavior starts to period, the well pressure behavior starts to be affected by the natural fracture and this causes a negative pseudo-skin factor, which is a function of time, and becomes a constant for large values of time, giving a second 1.151-slope straight line. This pressure behavior is similar to the one predicted by the models of Warren and Root and de Swaan for a uniform naturally fractured reservoir. Results from interference tests, for reservoirs having a natural fracture show that it is impossible to characterize uniquely the reservoir by means of the transient pressure test data alone. An integrated approach or transient pressure test data registered at several observation wells can be used for a unique characterization. From these tests, underestimation or overestimation of the reservoir parameters could result, depending on the location of the observation well relative to the natural fracture.

Introduction

Considerable amount of information can be found in the literature concerning the pressure transient behavior of hydraulically fractured wells. It is well known that fractures greatly affect the exploration of many reservoirs. Surprisingly, there are few, if any, quantitative data reported in the literature on the effect of vertical or horizontal fractures existing out in the reservoir matrix on the transient well behavior. This problem of fractures not crossing the borehole has been investigated experimentally by Huitt and Ollos. Huskey and Crawford used a potentio-metric model to study the effects of vertical potentio-metric model to study the effects of vertical fractures not crossing the borehole on the steady-state well behavior. Gureghian investigated, by variational methods and a potentiometric model, the effect of fractures in a potentiometric model, the effect of fractures in a confined aquifer on the steady-state flow behavior. He studied both intersecting and nonintersecting fractures.

It is believed that natural fractures may exist out in the reservoir and would affect the pressure well behavior. pressure well behavior.
Chemical Inhibition of Halite Scaling in Topsides Equipment
Authors: Frigo D. M. , Jackson L. A. , Doran S. M. , Trompert R. A.
Published: December 2007

Carbonate or sulphate scaling is usually mitigated by using chemical inhibitors that alter the growth mode of the scale mineral, but with halite scaling the apparent absence of a suitable inhibitor has meant that periodic removal with low-salinity water has been favoured. We report laboratory testing and the first field application of a chemical inhibitor for halite scaling. The inhibitor was field-tested in the Leman gas field (North Sea), where halite scaling occurs in gas-compression equipment due to evaporation of water from brine droplets carried over from the gas-water separator. The scale reduces the efficiency of both compressor and cooler, necessitating regular costly cleaning of the internals. After a recent system clean out, the cheap, non-toxic halite inhibitor was dosed continuously for 3 months into the production stream downstream of the gas-water separator. Whilst halite deposition was not completely suppressed, an increase in compressor efficiency was observed for all compression stages compared with recent non-inhibited data. A significant improvement in gas-cooler efficiency and a reduced tendency to block gas-flow meters, were also observed. This indicates that the inhibitor has considerable potential for cost-effective control of halite scaling, possibly as an alternative to periodic removal or in combination with it.
The Application of Oil Soluble Scale Inhibitors into the Texaco Galley Reservoir. A Comparison with Traditional Squeeze Techniques to Avoid Problems Associated with Wettability Modification in Low Water-Cut Wells
Authors: Jenvey N. J. , MacLean A. F. , Miles A. F. , Montgomerie H. T. R.
Published: December 2007

Advances continue to be made into the squeeze application experience of Oil Soluble Scale Inhibitors (OSi). Recent challenges within the North Sea include applying the chemical to inhibit scale in brines with high calcium levels, produced from variable permeability, water sensitive reservoirs at temperatures up to 165°C. In some cases, additional constraints such as an effective limit on fluid injection pressure can also pose a challenge.

This paper is intended to outline the problems experienced in the Texaco Galley reservoir, from a historical laboratory and field perspective using traditional techniques, before going on to describe the use of an OSi package to solve the problems, increase reservoir recovery & impact on field economics. Firstly it will be described why effectively ‘dry’ Galley wells had to be treated at such an early stage due to uncertainty in the prediction of the water cut profile. Although reservoir simulation did predict reasonably early seawater breakthrough, intuitively it was felt that the actual progression might be more significant due to the presence of high permeability streaks.

A description of the laboratory study that was carried out to support the use of a traditional water based scale inhibitor for well 15/23a-G1 will be given. The subsequent field treatment, using a low molecular weight nonionic amphiphile package, additive free diesel (AFD) spacer, water based scale inhibitor and AFD overflush will be described. Pressure problems experienced during the treatment and the ultimate, permanent loss in well productivity will be shown.

Finally, a description of the laboratory study and core floods carried out to further investigate the application of an OSi package on a second, very similar well 15/23a-G3z, will be given. This section will highlight the realisation of the potential advantages of OSi over traditional treatments including: early scale inhibition; reduction of backpressure during injection; minimum deferred oil production; & most importantly increased productivity following treatment.
Scaling Challenges in Tinggi Operation - A Case History of Scaling Management
Authors: Kabir A. H. , Haron J.
Published: December 2007

In this paper we describe a case history of a raging battle against scale deposition in the production system of Tinggi oil field in offshore Terengganu, Malaysia. This field experienced a sharp production decline from 1995 to 1997 at a rate of 26% per year. Scale deposition in various parts of the production system together with sand and emulsion caused widespread equipment/instruments failure, valves/chokes malfunction and most importantly severe piping restrictions at various points of the entire production system, surface and subsurface. A facilities capacity review study was conducted in order to differentiate between real facilities bottlenecks and scaled up restrictions. Pin pointing all the scaled up bottlenecks was quite a challenge. Diagnosis methods included visual inspection, pressure drop comparison, temperature sensing and gamma ray scanning. All scaled up points were successfully detected and cleaned up. As a result of this work together with sand, emulsion control and other production optimization efforts, oil production started to pick up by mid 1998. Production increased by 64% within a year with a total gain of 3.7 MSTB/d.

A comprehensive scale management plan was put together, both short term and long term. Routine scale cleanup, identification of scale-prone source reservoir and its management, scale inhibitor chemical injection program, routine stroking of control valves, scale buildup monitoring program of surface flowlines are some of the short term measures taken. Amongst long term measures, a study of effectiveness of Magnetic Fluid Conditioners (MFC) has been initiated. One commercial magnetic tool has been tried so far, with no benefit observed. While long term study continues, short term measures have brought the situation completely under control.
Effective Treatment of Subsea Wells with a Solid Scale Inhibitor System
Authors: Bourne H M , Heath S M , McKay S , Fraser J , Stott L , Müller S.
Published: December 2007

Aqueous based scale inhibitor squeeze treatments have been routinely deployed on Total Oil Marine’s North Alwyn field for many years. More recently, declining reservoir pressure in parts of the field, coupled to poor reservoir communication has led to a considerable increase in the time required to bring treated wells back onto production. On subsea well 3/4a-15s, it was anticipated that extended shut-in periods would be required to allow sufficient pressure build up for production restart following a platform squeeze.

To minimise deferred oil cost associated with scale inhibitor treatments an alternative deployment technique has been applied to treat subsea wells such as 3/4a-15s on North Alwyn.

A weighted solid scale inhibitor capsule, suspended in a carrier brine has been pumped to the wellhead and allowed to fall, under gravity into the sump. On reaching the sump, the diffusion of scale inhibitor from the capsule established a concentration gradient, which delivered a near constant level of inhibitor over the lifetime of the treatment.

The subsea well on North Alwyn treated using this technique returned to production in less than 24 hours. In addition, the encapsulated inhibitor treatments have out-performed previous squeeze treatments, protecting a large volume of water to the minimum inhibitor concentration (MIC).

This paper will describe the concept of the delivery system, details of the treatments and present the return profiles.
Planning and Execution of a Field Trial Utilising New Invert Emulsion Squeeze Technology
Authors: Smith R. N. , Lawless T. A. , Bourne H. M. , Brunger A. , Nicoll D. , McGee Kerr , Hurtevent C. , Ainsworth A.
Published: December 2007

A chemically advanced, safe, controlled delivery system, utilising invert emulsion technology, with the aqueous phase containing scale inhibitor in solution, has been developed and manufactured for evaluation in a North Sea field trial. Benefits arising from the implementation of this new technology include rapid oil returns in an immediate post-squeeze era, reduction of deferred or lost oil costs, the potential to improve contact between inhibitor and in-situ adsorption sites and the ability to formulate packages for sensitive formations and low water cut wells.

It is important for squeeze operations, that the emulsion can be injected safely downhole and encouraged to "break" during shut-in, allowing the aqueous inhibitor to be released and contact the pore structure, promoting effective retention. The "broken" oil phase maintains continuity between pore spaces and promotes rapid oil productivity to return, post-squeeze, as a result of relative permeability effects. The product will provide a safe application route for scale control in wells with pressure support limitations, drawdown restrictions and water sensitive formations.

This paper reviews the team approach undertaken by chemical process plant, service company, oil company consortia and research and technology service providers to facilitate the first field trial of this novel, scale squeeze process.

Extensive experimental evaluations and plant scale-up trials have been undertaken to develop a suitable chemical for field use. Emulsion manufacture requirements, phase volume considerations, destabilisation routes and rheological characteristics are discussed. Laboratory and offshore compatibility trials with appropriate field fluids are reported, together with core-flood investigations, these experiments reveal equivalent inhibitor returns to normal squeeze treatments, but post-squeeze oil production for the emulsion system shows inherent benefits.

A well with a sulphate scaling problem and history of deferred oil production post-squeeze has been selected for a field trial of this new technology. The field treatment is discussed and preliminary post-squeeze results evaluated.
Potential Application Of Amine Methylene Phosphonate Based Inhibitor Species In HP/HT Environments For Improved Carbonate Scale Inhibitor Performance
Authors: Graham G. M. , Dyer S. J. , Shell P. Shone
Published: December 2007

In recent years a number of new HT/HP reservoirs have been developed in the North Sea, for example the ETAP (Eastern Trough Area Project) and Shearwater fields, which have a number of important "scale" control issues. In addition to harsh downhole conditions (T > 175°C; P • 13,000 psi), high salinity (HS) formation water chemistries indicate that the control of inorganic precipitates in these systems will be very important. Two aspects, in addition to their ability to prevent scale formation, have been demonstrated in previous studies to be of significant importance in the choice of appropriate scale inhibitors. These are: (i) inhibitor/brine compatibility and (ii) the thermal stability of the scale inhibitor.

Previous reported work has strongly indicated that amine methylene phosphonic acid based inhibitor species such as Penta-Phosphonate (DETPMP) and Hexa-Phosphonate (TETHMP) are considerably less thermally stable than polymeric species such as PVS and VS-Co species. Significant thermal stability issues have been recorded for DETPMP and TETHMP based species at temperatures < 130°C, whereas polymeric species exhibit good thermal stability when tested at temperatures up to 180°C. As a consequence the phosphonate based species have been reported as less applicable for deployment in HT reservoir systems than certain polymeric species, such as PVS and VS-Co species. However, more recent studies examining a range of different amine methylene phosphonic acid based inhibitor species have shown that certain species are thermally stable at temperatures in excess of 160°C. This thermal stability, coupled with more effective carbonate scale inhibition performance of the phosphonates, may make them more applicable for carbonate scale in certain HP/HT fields. In addition, examination of the molecular structure of the different amine methylene phosphonic acid species allows initial interpretation of the factors controlling thermal stability of such species. This paper presents an improved understanding of the factors controlling thermal stability/degradation of generically different scale inhibitor products. It also demonstrates how relatively small changes in the structure of phosphonate based inhibitor species can impart significant improvements in thermal stability and consequentially their potential application in HP/HT reservoir systems.
Scale Dissolver Development and Testing for HP/HT Systems
Authors: Proctor S. M.
Published: December 2007

Calcium carbonate scale is commonly found deposited in process system configurations and upper tubulars of oil and gas producing wells. Remedial treatment of this scale can be costly and time consuming and requires acid dissolution. Hydrochloric acid is commonly used as a superficial low cost acid treatment but can often result in tubular damage. In an attempt to limit this problem, corrosion inhibitor packages are often incorporated into the acid treatment, however success has been limited. Alternatively organic acids can be used. They offer a practical alternative to mineral acids with lower corrosion implications, but to date have typically been deployed in fields where operating temperatures do not exceed 100°C.

Continued advancement in oilfield production technology has allowed the exploration of high temperature, high pressure fields, which in turn has led to the introduction of corrosion resistant alloys into production assemblies. The corrosivity of existing carbonate scale dissolving mineral acids for HP/HT application can be controlled, however existing corrosion inhibitor packages do not exhibit good environmental properties. As a result of this industry trend there is a requirement for scale removing chemicals with good environmental characteristics. These products must be capable of withstanding HP/HT conditions whilst exhibiting good performance and in particular be compatible with the high alloy steels which are currently utilised.

This current test work has investigated the possibility of an inhibited carbonate scale dissolver treatment that will combine a high carbonate dissolution rate with low corrosivity towards the high alloy steels commonly in use in HP/HT systems. Various static corrosion test methods were considered throughout the duration of the test work, and a method for high temperature testing was developed.

This has resulted in organic carbonate scale dissolvers which are suitable for use in HP/HT fields, that efficiently dissolve carbonate scale whilst providing adequate corrosion protection towards a range of novel corrosion resistant alloy steels.

The data contained in this paper details the development of these products and also discusses the test methodology and equipment design employed to evaluate these products.
Combined Scale Removal and Scale Inhibition Treatments
Authors: Smith P. S. , Clement C. C. , Rojas A. Mendoza
Published: December 2007

Calcium carbonate scale impacts oil production in a large number of fields worldwide. This scale is generally managed by acid washing to removal the scale and/or by performing scale inhibition treatments. The choice between inhibition and regular stimulation is cost driven, with high cost operations generally selecting inhibition. However, even in wells where inhibition is planned, some scale can be deposited either prior to scale inhibitor deployment, or after the end of the scale inhibition treatment life. Consequently, stimulation treatments are required in many wells, in order to remove calcium carbonate scale.

Combining scale inhibition with scale removal treatments offers several advantages. Firstly, in many operating areas, it would reduce the well intervention cost by making the operation a single intervention, offering significant economic benefits and a reduction in well intervention risk. Secondly, pumping a combined treatment not only reduces the risk of scale re-precipitation during the stimulation treatment, but it ensures that the zones that are stimulated are also inhibited. This directly protects value added by the scale removal treatment.

This paper details the development of combined scale removal and inhibition treatments, from project initiation to readiness for field trials. The main challenges that need to be addressed in order to achieve an effective combined treatment are discussed. Data from a laboratory study, investigating the potential for combining scale inhibitors in hydrochloric acid, organic acid and scale dissolver systems are presented and the most effective combined systems are identified.
Experience Gained from 318 Injection Well KOH Clay Stabilization Treatments
Authors: Norman C. A. , Smith J. E.
Published: December 2007

Water injection in clay sensitive sandstone formations often results in decreased permeability and low injectivity. Some types of clays, including montmorillonites, swell upon contact with fresh water, plugging pore throats and reducing permeability. Migrating clays, including kaolinites and illites, reduce permeability as they become trapped in pore throat openings. KOH (potassium hydroxide) clay stabilization results from the interaction of caustic with the clay in the presence of potassium ions. The KOH-clay chemical reaction permanently alters the clay chemistry so that the clay minerals are unaffected by changes in water composition. Several field case histories, discussed in the following paragraphs, demonstrate that KOH can mitigate the effects of both swelling and migrating clays. Field results indicate that a single KOH treatment is effective over the economic life of the well.

Laboratory studies and empirical results indicate that the most important considerations for optimizing KOH treatment results are: 1) KOH concentration; 2) KOH contact time with reservoir rock; 3) maintaining a constant flow rate of the KOH solution during the treatment, and; 4) reservoir temperature.

The majority of KOH treatments have been applied in Cretaceous sandstone formations in the Powder River Basin of Wyoming. However, KOH offers the potential for injectivity improvement in other clay sensitive formations, and should be considered as an alternative to hydraulic fracturing in some areas. Finally, a simple waterflood simulation is presented in order to evaluate the economics of KOH.
Water and Gas Coning toward Finite-Conductivity Horizontal Wells: Cone Buildup and Breakthrough
Authors: Umnuayponwiwat Suwan , Ozkan Erdal
Published: December 2007

This study concludes that the shape as well as the time of breakthrough of a water or a gas cone are significantly affected by the pressure drop within the wellbore. An analytical model is used to demonstrate features of the movement of a cone when pressure drops in the wellbore are important. It is shown that wellbore hydraulics produces a self-sharpening feature and this leads to breakthrough at the heel of the well. This behavior may not be demonstrated by assuming an infinite-conductivity wellbore. The model described here may be used to assist simulation studies by providing specifics on the movement of the cone.
Reducing Uncertainty in Reservoir Management Using Semi-Analytical Modeling and Long Term Daily Data Acquisition
Authors: Foster Gary A. , Wong Dale W.
Published: December 2007

The availability of accurate daily pressure, flow rate and temperature data allows the reservoir engineer an opportunity to model the reservoir behavior and predict reservoir performance with increased accuracy. Tools currently available including decline analysis, simple analytical methods, complex analytical methods and the use of material balance techniques provide independent approaches to the problem of production forecasting and reserves determination. Each method is limited to an inherent level of accuracy based on assumptions of reservoir size and the effect of interference. A field case is used to demonstrate the range of predictions using the alternate methods at different stages in the life of the reservoir. Each member of the exploration and development team including production operations, accounting and the IS group needed to be satisfied their requirements were being met using a daily data reporting system. A low earth orbit satellite system was chosen to transmit data based on reliability, cost and the ease of use and implementation.
Improved Completion Method for Mesaverde-Meeteetse Wells in the Wind River Basin
Authors: Long Ed , Kundert Pat
Published: December 2007

In 1996, Tom Brown, Inc. began drilling new deep Mesaverde-Meeteetse formation wells in the Muddy Ridge field in central Wyoming. The formations consist of many layers of potential pay zones over a long gross interval. Total depth of the wells is about 13,000 ft, with the uppermost pay zones at about 9,500 ft. Over this 3,500-ft gross interval, as many as 50 potential pay zones may be present.

Initial completions consisted of grouping three or four of the best-developed zones together. The zones were then hydraulically fractured and flow-tested for an extended period so production could be determined. Conventional retrievable bridge plugs and packers isolated additional zones as the completion progressed up the hole to new zones. Because of the individual stimulations and extensive flow-testing, the typical well completion lasted several weeks (or months).

The challenge was to find a new streamlined completion method that would reduce the time required to place the wells on production. To meet this challenge, a composite fracturing plug (CFP) was used. A CFP holds pressure from above the tool while successive zones are treated, but it allows flow from zones below it during cleanup.

The current general procedure is to perforate 8 to 10 zones in the lower Mesaverde formation and to perform a hydraulic fracture treatment down the casing. A CFP is then run on wireline and set above the zones just stimulated. Additional Mesaverde zones are perforated, and a second fracturing treatment can be pumped the same day. Pinally, tubing with a pumpoff bit is snubbed into the well, and all the CFP's are drilled out. The entire Mesaverde-Meeteetse group of zones was perforated and fractured in 3 to 5 days when this technique was used.

Using composite fracturing plugs has reduced the well completion to a matter of days, and has made rigless completion possible for the stimulation phase.
Use of Hydraulic Fracture Diagnostics to Optimize Fracturing Jobs in the Arcabuz-Culebra Field
Authors: Wolhart Stephen L. , Berumen Sergio , Cipolla Craig L. , Barton Colleen A. , Branagan Paul T.
Published: December 2007

This paper presents the results of a study conducted to improve hydraulic fracturing and field development in the Arcabuz-Culebra Gas Field in Mexico. Hydraulic fracture mapping was performed on four stimulation treatments using a combination of tiltmeters (surface and downhole) and microseismic imaging. Fracture mapping was complimented by 3-D fracture modeling and geomechanical modeling. Data analyses resulted in recommendations regarding well positioning and hydraulic fracture design.
A New Approach for Predicting Frictional Pressure Losses of Non-Newtonian Fluids in Coiled Tubing
Authors: Medjani B. , Shah S. N.
Published: December 2007

The importance of the pressure loss in the design of treatments for various field applications while using non-Newtonian fluids necessitates the estimation of the pressure loss in the reeled part of the coiled tubing unit.

The present work discusses the analysis of frictional pressure loss of non-Newtonian fluids flowing through coiled tubing and includes the effects of fluid concentration and the influence of coiled tubing curvature and length. An experimental investigation of three polymeric solutions is conducted to predict the frictional pressure losses related to their flow behavior in coiled tubing.

A total of 1500 ft of 1-in., 5000 ft of 1 1/2-in. and 3000 ft of 2 3/8-in. coiled tubing was used for this purpose. Also, straight sections of coiled tubing were employed for obtaining frictional losses in straight sections, which then are compared with those of reeled coiled tubing.

Experimental results are also compared with the correlations presented earlier by Srinivasan for Newtonian fluids and McCann for non-Newtonian fluids. From the data analysis, it was found necessary to develop a new model which includes Dean number. The Dean number takes into account the curvature effect. This new model is proposed for the prediction of the friction factor in coiled tubing for fluids exhibiting power law pseudoplastic type behavior with flow behavior index less than unity.
Case Studies Demonstrate That Effective Soluble Scale Removal Treatment Outperforms Bull Heading
Authors: Larsen Henrik Aslak , Peterson Chad D.
Published: December 2007

Scale is often encountered in producing well bores. This paper presents five cases where soluble scale has been removed through an optimized approach of coiled tubing conveyed tools and hydrochloric acid. A comparison between different methods available to the industry is made. The paper covers removing carbonates, sulfides and cement from sub-surface safety valves and gravel pack screens. Field comparisons have been made between simple bull heading of solvents, impact hammers, motor and mills, simple jetting nozzles, and optimized jetting tools with solvents. The combination of solvents and tools with optimized hydraulics is shown to be highly effective.

The results are presented with increase in production rates where applicable. Three examples are shown where increase in production ranges from 50% to an 8-fold increase.
Managing Differential Pressures During Coiled Tubing Operations
Authors: Rosato M. J. , Courville P. W.
Published: December 2007

Coiled tubing (CT) is routinely deployed in wells producing from multiple pay intervals. Multizone completions induce pressure gradients that present significant operating risks to CT operations. Kicks and lost circulation can cause reservoir damage, blowouts, and lost pipe. Countless CT strings have been lost in wells because of uncontrolled well responses during treatments.

Wellsite observations have improved the diagnosis and prevention of circulation problems caused by differential pressures. Some of the specific factors influencing these problems are formation fluid levels, well geometry, interval height, and temperature. Reservoir management techniques can reduce the hazards imposed by differential pressures. However, because kicks and lost circulation cannot always be avoided, contingency plans are necessary. Prejob calculations and planning procedures can help operators establish practices that minimize the adverse effects of kicks and lost circulation.

A comprehensive strategy for CT operations includes contingency planning. While some risk must be assumed in all well-intervention processes, proactive planning can minimize problems and increase the potential for success.
The Removal of Hard Scales From Geothermal Wells: California Case Histories
Authors: McClatchie D. W. , Verity R.
Published: December 2007

The Geothermal Industry’s largest remedial budgetary cost involves the removal of scale from its existing completions. From it’s inception forty years ago, the geothermal industry has tried many different systems and applications for the removal of very hard scale from their injection and production wells. Today the most widely used and accepted method for hard scale removal has been the use of a workover rig utilizing a bit and scraper. This method, although partially effective, does not fully address the impediment of scale in the well conduit – a bit and scraper simply cannot remove what it cannot reach. In addition, with the advent of high alloy materials to combat the corrosion effects of these scales, along with pressure depleted formations, this method is proving to be inadequate as it can cause severe damage to the expensive wellbore tubulars. This paper reviews and discusses several case histories of a newly developed technique for removing these very hard geothermal scales.
A New Approach to Monitor Tubing Limits
Authors: Zheng Andrew S. , van Adrichem Willem P.
Published: December 2007

This paper presents a new approach to monitor coiled tubing tension and pressure limits during operation. The conventional way to monitor the tubing limits in real time is through monitoring the section right below the stripper. It works well for a single-wall tubing string operating in a shallow well with low wellhead pressure. For high-pressure wells, deep wells or high deviation wells, this becomes inadequate because the critical section may not be at the section below the stripper. Instead of monitoring the tubing limits at a specific section (such as the section below the stripper), the model presented herein dynamically tracks and monitors the critical section of the tubing during operation.

Our approach starts with a new way to express the tension and pressure limit curve of the coiled tubing. The use of effective force to generate the limit curve facilitates the task to identify the critical section of the coiled tubing during operation. To identify the critical section, the distributions of tubing force and pressure difference along the coiled tubing downhole are calculated during the operation. This information is used to calculate the safety factor along the coiled tubing string, from which the critical section is identified. A software based on this approach has been developed, which allows operators to dynamically track and monitor the critical sections during operation. By coupling with surface measurements (such as ovality) in real time, it significantly improves operators’ ability to monitor tubing limits.