bluuebunny/crossref_metadata_2025_split huggingface dataset:
Asphaltene Inhibitor Evaluation in CO2 Floods: Laboratory Study and Field Testing
Authors: Yin Y. Ralph , Yen Andrew T. , Asomaning Sam 
Published: December 2007

Abstract
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

Abstract
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.

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 &gt; 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 &lt; 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

Abstract
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

Abstract
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.