bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of a Highly Efficient Multistage Stimulation Technique for Horizontal Wells
Authors: Al Mutawa Majdi , Al Matar Bader , Rahman Yousef Abdul , Liu Hai , Kelkouli Redha , Razouqi Maen 
Published: February 2008

AbstractIn the recent years horizontal well technology evolved in the Middle East field development strategies becomes favored over vertical and deviated wells offering the advantage of maximized reservoir contact, higher production rates and better access to reserves. However, most of these horizontal wells are completed openhole with little alternatives for stimulation, water shutoff or workover treatments. A very challenging task to stimulate long openhole sections effectively due to poor acid distribution especially in reservoirs with high permeability streaks that require effective diversion techniques. The efficiency of chemical diverting agents in terms of flow distribution and uniform coverage is limited when it comes to treat such complex wells with long openhole intervals (see Fig. 1).This paper illustrates a case history where an innovative technique was used on stimulating a naturally completed horizontal well that experienced a production drop to zero shortly after the completion in 2004 due to formation damage and incomplete cleanup. This technique combined mechanical and chemical diversion, using selective openhole completion allowing the wellbore mechanical segmentation into six small intervals based on petrophysical and reservoir evaluation, so that the selected sections can individually be stimulated evenly and inflow contribution from the entire openhole section can be maximized win one continuous operation.The treatment used the advanced emulsified acid technology to achieve deep penetration and better etched fracture conductivity. Viscoelastic surfactant self-diverting Acid (VES diverting acid) was used as the chemical diverter to assure good zonal coverage across each stimulation stage. Greatly increasing the effectiveness of the treatments the combination of technologies allowed successful stimulation of the well with 20:1 permeability contrast. The last stabilized measurement indicates sustained natural production of 10,000 bopd, which is five times the field average and three times greater than the best well in the field without requiring artificial lift.
High-Water-Cut Wells Stimulation Combined Viscoelastic Surfactant
Authors: Al Mutawa Majdi , Al Matar Bader , Dashti Abdulaziz Abdulla , Kelkouli Redha , Liu Hai , Razouqi Maen 
Published: February 2008

Abstract
Dual completed wells producing from the mature carbonate formation in northern Kuwait are encroached by injected water from adjacent wells presenting a challenge for the operating company. Greater oil demand coupled with limited surface water handling facilities increased the importance of stimulating this type of challenging wells due to the drastic permeability contrast across the pay zones.
Typically the treating fluid in a matrix treatment flows into high permeability sections and/ or high water saturation "thief zones" resulting in higher water cut due to the over stimulation of the water zones instead of the oil bearing zones. The objective of the present field case study was to place the stimulation fluid equally throughout all intervals of the oil bearing layers while temporary protect the zones suspected to be mainly contributing with water from the stimulation fluid, using two different types of viscoelastic surfactant (VES) polymer free diversion systems placed with coiled tubing (CT) providing effective plugging of the layers producing water and providing a uniform stimulation fluid coverage across the entire pay zone. Subsequent production rates showed substantial oil production increase and water production decrease, 360% and 40% respectively.
Monitoring and Prediction of Cleanup Production During Sampling
Authors: Zazovsky Alexander 
Published: February 2008

Abstract
A novel concept for cleanup prediction during sampling is proposed. This concept shifts focus to the early phase of cleanup, allowing for early predictions of pumpout time or produced volume using optical fluid analysis logs versus given contamination targets. The early phase of cleanup potentially provides a great deal of information to be used in prediction of cleanup, because this phase is strongly affected by both the local flow pattern and the contamination transport and deals with a larger range of optical density variation.
A new approach to cleanup prediction is based on a truly 3D model of flow and contamination transport to the probe production area at the wellbore wall covered by mudcake. This model better captures the initial phase of cleanup than the conventional spherical flow model, which incorporates axisymmetrical contamination transport to a small production sphere located at the wellbore axis.
The new model provides the signature of 3D contamination transport on cleanup dynamics, which is controlled by the ratio of invasion depth to wellbore radius. The analysis of new problem solutions reveals new details of cleanup evolution. In particular, the transition from a predominantly circumferential regime of cleanup to a predominantly vertical cleanup has a distinctive signature that can be used in cleanup progress monitoring and the reconstruction of initial invasion depth.
Examples of sampling job data processing that support the new concept are provided. They indicate that decent estimates of pumpout volumes can be obtained 3 to 5 times earlier using the new approach.
New, Highly Effective Asphaltene Removal System With Favorable HSE Characteristics
Authors: Frost K. A. , Daussin R. D. , van Domelen M. S. 
Published: February 2008

Abstract
Paraffin and asphaltene problems can significantly reduce well profitability, causing troublesome operational issues, damaging formations, and decreasing production. Although often mentioned together, paraffin and asphaltene are distinctly different in their composition and behavior and different remediation solutions are required. In comparison, asphaltene deposition and removal is much more problematic than paraffin deposition and removal. The most common asphaltene removal techniques use xylene or xylene mixtures, which typically have limited effectiveness in addition to undesirable health, safety, and environmental characteristics.
This paper describes laboratory investigation of alternative solvent systems for removal of asphaltene deposits. Theoretical solvency parameter comparison based upon methods developed by Hildebrand and Hansen allowed solvents and cosolvents to be screened. The problem of formation wettability was addressed through the use of water-wetting surfactants. Finally, it was discovered that the primary solvent and cosolvent(s) could be dispersed in water yielding a water/aromatic solvent mixture that would not only effectively dissolve and disperse asphaltene, but also leave the formation in a water-wet state to delay production decline.
The new water-based asphaltene removal system was first applied in southern Europe in 2005. Since then, the system has been optimized for broader global operations whilst maintaining the favorable HS&E characteristics of the initial development. The system is unique as it provides a high-flashpoint water/solvent mixture with solvency power often greater than xylene and the additional benefit of leaving the formation strongly water-wet.
Concentric Annular Packing System Successfully Frac Packs Longest, Highly Deviated Intervals at Highest Record Treatment Rate Attempted Worldwide: Angola Case History
Authors: Lemesnager Fabien , Gavalda Jean , Chassagne Alain , Cortier Alexandre , Ranjeva Jean-Michel 
Published: February 2008

Abstract
Total E&P Angola operates the deep offshore ROSA field on Block 17. On the fifth development well in the field. Two zones in the Oligocene sandy layers are transversed at a well deviation of 48° and required the implementation of the stacked frac-pack technique. The perforated length of zones was approximately 118 ft and 213 ft.
Multiple fracture initiation and early screen out were expected, requiring consideration for an enhanced frac–packing method. In order to facilitate placement reliability, a concentric annular packing system was chosen to limit slurry bridging during placement in combination with an aggressive pumping design (25 bbl/min for the lower zone and 32 bbl/min for the upper zone). This paper will discuss the system used for successful frac packing and how it provided alternate paths for the slurry flow when a bridging occurred while keeping the same high flow rate.
Data collected on the two zones during treatment have shown that early annular bridging had occurred during slurry placement, but the system had successfully created a high-velocity flow path with minimal pressure drop to bypass the bridge. Once the bridge was bypassed, the full flow area was again used, minimizing turbulence and potential for damaging screens.
The paper will describe:
The target zones The concentric annular packing system design Integration of the concentric system in the dual stacked frac packs architecture Hole pattern design and velocity calculations in shroud orifices The service tool design for stack frac-packs Pumping treatment analysis Observations gathered during the job How technique and job-treatment design versus use of a regular frac-pack system or other alternate-path systems was justified.
Although alternate path technique has been used in frac-packing more than 30 times globally, the stack frac-pack performed on this case history well (WELL-5) holds the record for being the longest treated length, steepest deviation, and highest pumping rate ever attempted thanks to the concentric annular packing system originally designed for the horizontal gravel pack completions.
High completion efficiency was achieved. Productivity data are provided (skin, PLT, etc).
Surveillance and Diagnostics of Permanent Bottomhole Gauge Data Coupled with Geomechanical Modeling to Identify Sources of Formation Damage
Authors: Holicek R. A. , Adachi J. , Viloria L. A. , Mese A. I. , Traore Y. , Singh A. P. , Hanssen R. 
Published: February 2008

Abstract
With increasing availability of real-time downhole measurements in completions, more and more uses of these data are evolving. A deepwater field in the Gulf Of Mexico (GOM) consisting of numerous wells with permanent bottomhole gauges has been on a surveillance and diagnostic program for over 3 years. Pressure transient analysis of shut-ins give key performance indicators (KPIs) such as permeability-height (kh), skin (s) and current average reservoir pressure (Pave); the KPIs are summarized on a quarterly basis and compared with historical trends to check well performance. For the fields studied, the KPIs have proved valuable not only for production monitoring, but also as an investigative tool for larger-scale problems such as compaction, subsidence, depletion, and fines migration. This paper summarizes case histories from two fields where reduction in kh over time, and increasing skin over time led to a more in-depth study of the reservoir geomechanics. The geomechanical characterization of the reservoir allows for further insight into the behavior, increased knowledge of the production history, and allows for estimation of subsidence and compaction effects during future pressure transient tests.
Evaluation of Refracure Reorientation in Both Laboratory and Field Scales
Authors: Liu He , Lan Zhongxiao , Zhang Guoliang , Hou Feng , He Xiuqing , Liu Xinghui 
Published: February 2008

Abstract
Most tight oil reservoirs need to be hydraulically fractured before putting into production. Refracure is a necessary and efficient way to control production decline after first fracturing treatments. It has been recognized that reorientation of propped refracure treatments can contact with undepleted reservoir areas and that refracure reorientation is one of the main mechanisms for production enhancement.
In this paper, laboratory tests for fracture reorientation were investigated. Case histories of refracure treatments and tiltmeter mapping results were discussed. All the fracture treatments included a novel design technique of pumping paraffin balls approximately half way through the propped treatment in an attempt to initiate new fracture growth through different a perforation interval or in a different orientation. Tiltmeter mapping results indicated that fracture reorientation occurred for the majority of these refracure treatments studied. Case histories involved two tight oil reservoirs in the Daqing oilfield, China. More significant post-frac production improvements were observed for the refracure treatments with fracture reorientation.
Smart Mud Filtrate: An Engineered Solution To Minimize Near-Wellbore Formation Damage Due to Kaolinite Mobilization Laboratory and Field Experience–Oseberg Sør
Authors: Watson R. B. , Viste P. , Kaageson-Loe N. , Fleming N. , Mathisen A. M. , Ramstad K. 
Published: February 2008

Abstract
Numerous papers have been published on the influence that kaolinite mobilization has on well productivity. However, less attention has been directed toward identifying methods to minimize the detrimental impact of this mobilization. This paper will detail the pro-active approach that the authors took in engineering solutions to enhance oil productivity by reducing kaolinite mobilization. Specifically the paper will focus on the experiences from Oseberg Sør (North Sea). Significant formation damage has been attributed to kaolinite mobilization in this field. This damage can occur at any stage within the well lifetime from initial drilling and through the production lifecycle. SPE 107758 provided details of a unique chemical that can be incorporated into scale inhibitor squeeze treatments to reduce kaolinite mobilization while a well is in production. This paper will focus on the development of smart mud filtrate technology that incorporates kaolinite fixation agents that minimize clay mobilization within the near wellbore during drilling.
Do Viscoelastic-Surfactant Diverting Fluids for Acid Treatments Need Internal Breakers?
Authors: Huang Tianping , Crews James B. 
Published: February 2008

Abstract
Matrix acidizing and acid fracturing treatments have been regularly applied for enhancement of oil and gas production. The success of the acid treatments requires uniform distribution of acid fluids across long treatment intervals or areas especially for vertical, horizontal, extended reach and multilateral wells with open hole completions. The unique properties of viscoelastic surfactant (VES) fluids provide good acid diversion fluids for blocking acid fluid flow into higher permeability sections in order to force the stimulation fluid into the lower permeability sections.
Recent SPE publications have shown that VES fluids used for acid diversion fluids have caused formation damage for matrix acidizing and acid fracturing, requiring a longer flow back periods, particularly for low permeability and depleted gas formations. Internal breaker technologies for VES fluids have been developed for hydraulic fracturing and frac-packing treatments. The internal breakers give a controllable break and go wherever the VES fluid goes, breaking the VES fluid into easily producible fluid.
This paper will introduce a VES organic acid fluid with internal breakers for treating carbonate reservoirs. The VES organic acid system is unique and will not generate noticeable viscosity until the acid starts to spend. The VES within the acid fluid reaches it highest viscosity as the acid completely spends and diverts fresh acid to new locations. After acid treatments, the internal breaker becomes activated to break the VES micelles, and the fluid loses its viscosity and flows back during production, minimizing any potential damage.
The paper will discuss lab results which demonstrate that the VES product generates very high viscosity at low shear rates in the spent acid fluid, and VES fluid will not broken only by contacting hydrocarbons. Further demonstrated is how internal breakers are available that reduce the viscosity of the spent acid diverter fluid over a controllable period of time. Carbonate wormholing core flow tests show non-broken VES fluids in wormholes need much higher pressure drop than than broken VES fluids for mineral oil cleanup.
Dynamic Underbalanced Perforating Application Increases Productivity in the Mature High-Permeability Gas Reservoirs of Santa Ana Field, Venezuela
Authors: Medina M. , Morantes G. , Morales J. , Guevara W. , Romero J. , Gonzalez Y. 
Published: February 2008

Abstract
Located in Eastern Venezuela the Santa Ana Field is part of the most important gas province of Venezuela: Anaco District. Its main productive zones are the Merecure and San Juan formations, which are sandstones characterized by their high permeabilities (100 - 500 md) and low pressures (1200 - 2200 psi).
The wells in Anaco District are normally perforated using conventional static underbalanced techniques. The productivity of these wells was evaluated using nodal analysis techniques coupled with perforating performance simulations. The quality and amount of data was recognized to be limited. However, a qualitative diagnosis of these results indicated that the static underbalanced condition and the shaped charges used were not enough to effectively clean the perforation tunnel and surpass the near wellbore damaged zone.
Dynamic underbalanced perforating coupled with high performance charges was selected as the technology that would improve productivity in the challenging wells of Santa Ana. This technology has been applied in similar scenarios across the industry in recent years, although no documentation was found on its use in such low pressure environments.
This paper describes how dynamic underbalanced perforating was deployed successfully, while pushing the limits of its application envelope. To obtain a dynamic underbalanced condition in such a low pressure environment, the shot density had to be reduced to 2.5 spf, raising concerns about its effect on well productivity. Two wells were selected for this field trial. They were perforated using a TCP/DST string, which allowed the well to be tested immediately after perforating. Details of the diagnosis, planning, execution and evaluation phases of this project are described.
The resulting gas production and zero perforation skin represented more than a two-fold productivity increase compared with the target reservoir average well production. These results demonstrate the effectiveness of the technique under borderline conditions, and promote its application in similar scenarios worldwide.
This project shows the importance of production and perforating diagnosis, leveraging technology application and pushing the limit of dynamic underbalanced perforating in order to increase productivity in mature/low pressure assets.
Sand Control Completions for the Development of Albacora Leste Field
Authors: Pedroso C. A. , Sanches E. M. , Oliveira N. S. , Mickelburgh I. J. , Guimaraes C. R 
Published: February 2008

Abstract
The Campos Basin in Brazil is one of the most challenging areas for completions in the world due to the lack of formation consolidation, the large percentage of fines present in the reservoir, the heavy oil, the low frac gradients, the low net-to-gross ratio, the low bottomhole temperatures and the requirement for pressure maintenance.
The development of the Albacora Leste Field in the ultra deep water Campos Basin was a key component of Brazil's drive to achieve petroleum self sufficiency by 2006.
Because of the challenges presented by the heavy oil and the large geographical extension of the reservoir, the decision was made to develop the field with horizontal openhole gravel packs for both producers and injectors. Fifteen production wells and eleven injector wells were drilled and completed in the field.
As a result of the perceived technical complexity of the development, and requirement to maximize completion efficiency, the operator chose to maximize the integration of the services by bundling their acquisition from a single integrated services supplier, rather than contracting the required well construction services in a discrete manner, as had been traditionally done in the Campos Basin.
Horizontal openhole gravel packs, as planned for the development of Albacora Leste, were already an established and successful completion technique in the Campos Basin. However, the Albacora Leste wells were amongst the longest attempted in the basin, and due to the combination of the ultra deep water and limited sediment thickness, had significantly lower frac gradients than previously experienced.
The challenges of minimizing placement pressures, accurate modeling of gravel placement, rat hole mitigation, and injection well clean-up all had to be addressed. The solutions developed to meet these multiple challenges will be presented in this paper.
Development of Reactive Coatings to Protect Sand-Control Screens
Authors: Constien Vernon , Coffey Dewayne 
Published: February 2008

Abstract
Sand control screens are susceptible to plugging during installation in the wellbore and during production. One common source of plugging material is drilling fluid components left in the wellbore as whole mud or filtercake. In the past, screens have been coated to prevent plugging during installation. These early coatings were designed to dissolve at elevated temperature or be removed by acid treatment. While this approach protected the screens from plugging during installation, it did not address the potential for plugging by mud solids during production. To minimize the plugging due to mud solids, reactive coatings are being developed to protect sand control screens from plugging during installation and during production. New reactive coating formulations are designed with mechanical and chemical properties that will remain intact until the screens are placed in the wellbore. Once in place, the coatings begin to dissolve and release reactive materials such as acids, enzymes, or chelants into the near wellbore area to react with and degrade the drilling fluid components which could plug the screen.
Collapse Analysis of Screens Used in Horizontal Open Hole Gravel Pack Completion
Authors: Santos Anderson Rapello dos , Silva Patrick Perez da , Vargas Eurípedes do Amaral , Braga Arthur Martins Barbosa 
Published: February 2008

Abstract
Global increase in energy demand and the lack of opportunities onshore or in shallow waters are driving production of hydrocarbons towards deep and ultra deep-water basins, where reservoirs are usually formed by weak and unconsolidated sandstones that require sand control methods to prevent damage in surface and subsurface equipments.
Guidelines to select sand control systems are primarily based on sand exclusion, seeking to optimize balance between oil rate and fines production. Another aspect, often overlooked, is collapse strength of the system formed by the sand control equipment and the formation itself, subjected to mechanical loadings that change during life of the well.
This contribution presents a method to evaluate collapse strength of sand control systems taking into account mechanical interaction between the formation and sand control screens. Elastoplastic models are used to represent granular materials.
The most usual sand control system was studied: gravel pack with premium screens. A model to describe contact between granular materials (gravel and formation) and soil-pipe interaction is proposed. Results demonstrate that perforated base pipes used in premium screens may be oversized for applications under regular operating conditions.