bluuebunny/crossref_metadata_2025_split huggingface dataset:
Winning Productivity and Injectivity in Sabiriyah Upper Burgan: Life-of-field Approach to Tackle Development Challenges
Authors: Chetri H. B. , Baroon Bodoor , Al-Anzi Ealian 
Published: May 2009

Abstract
Sabiriyah Upper Burgan (UB) is a giant clastic reservoir in North Kuwait undergoing development efforts with water flood. Productivity indices as per historical data indicated these to be less than adequate and mismatching with the intrinsic reservoir permeabilities. This was a puzzle till a comprehensive review of the past pressure build up data was made and the results integrated with the-then perforation practices. More than 85% of the wells showed formation damage with a positive skin of +2 to +7, as per PBU data. Efforts were made to perform mud acid jobs without much success. After detailed review and performance analysis, recommendations were made to perforate new producers with TCP under balance, in addition to improvements in drilling mud chemistry. Subsequent PBU results of these wells indicated negative skin, which was also supported by better PIs.
The situation became a serious issue during initial phase of water flood and Injectivity tests. Injectors showed poor Injectivity indices. Though there had been multiple reasons for poor Injectivity, formation damage due to progressive plugging of pore throats was one of the major contributors. Detailed review of the dynamic behavior of the injectors led to the recommendations for improving the injection water quality by proper filtration, back flowing of the injectors prior to injection start-up and performing proppant frac jobs, if warranted. The implementation led to significant improvement in Injectivity. Phase-1 injection in the pressure depleted crestal area is in progress since last 3 years, thus sustaining production staying above the bubble point pressure.
Simultaneous to above, pore throat studies were conducted, leading to the conclusion that the pore throat size is very small with inherent risk of progressive plugging of injectors with time. In order to have life-of-field solution to Injectivity issues, recommendation was made to inject above parting pressure during the full field expansion of the water flood in 2010–11, on the basis of the results of Step Rate tests.
The case history of understanding and combating the formation damage in UB was a giant leap for rationalizing the way forward for its full fledged development.
Reservoir Pressure Depletion and Water Flooding Influencing Hydraulic Fracture Orientation in Low-Permeability Oilfields
Authors: Kuzmina S. , Butula K. K. , Nikitin A. 
Published: May 2009

Abstract
Hydraulic fracture azimuthal orientation depends on stress distribution in the formation and is considered to coincide with the maximal horizontal stress azimuth. Knowledge of the hydraulic fracture orientation is of critical importance in field development planning, including well spacing and pattern, the location of water injectors that will lead to a desired line drive mechanism, optimized reservoir drainage, and maximized recovery factor. This information is not less critical for infill drilling, fracturing "old" wells, refracturing, fracturing of sidetracks, and the knowledge of hydraulic fracture orientation of the water injector wells that are fractured by the mere injection process. It is also known that refracturing and pore pressure re-distribution will reorient the stress field not only in the near wellbore area but also in the far field.
Theoretical modeling and field experience suggest that hydraulic fractures do reorient under the influence of pore pressure changes because of reservoir fluid production and water injection. Field sector formation pressure distribution makes the fracture offset from maximal stress direction towards injection wells and this effect of local stress reorientation is more likely to occur in low permeable formations with low diffusivity and low horizontal stress anisotropy.
A number of complex fracture geometry orientation investigations were performed on low permeability formations in Siberia to understand the phenomenon. This included acoustic measurements and micro-seismic monitoring. Though the main purpose was to optimize fracture geometry by comparing measured and modeled fracture parameters, the importance of fracture orientation for reservoir development was even more significant.
The results undeniably indicate that a significant deviation of the field sector fracture azimuth from the maximal regional stress direction exists. It was discovered that the degree of deviation from the regional preferred fracture azimuth is affected by water injection and reservoir fluid production in the sector of the monitored well. Observations regarding the effect of fracture wing length asymmetry may also be explained by the disturbance of initial stress conditions. The results of this investigation will be used to further optimize hydraulic fracture design, reservoir pressure maintenance, including well spacing and well pattern, and water flooding strategies.
Recovery of an Oil Producer Severely Damaged by OBM Using an Advanced Barite Dissolver System
Authors: Davies C. , Twynam A. , Bulgachev R. , Harrington R. 
Published: May 2009

Abstract
BP in the U.K. North Sea attempted to drill a horizontal oil producer in the Harding field in 2006. Designed to produce an initial 10,000 blpd from 2000 feet of reservoir section before water break through, the well was compromised by the collapse of the lower hole due to chronic shale instability. This also resulted in the pre-drilled liner being stuck and set higher than initially planned. With less than 200 feet of reservoir sand exposed at the heel of the well (in close proximity to the water leg), the initial expectations were of 4,000 blpd. However the well was found to be badly impaired and produced 400 blpd. Although the well had been displaced to a carbonate based low solids oil based mud (LSOBM) prior to completion, a significant quantity of the barite weighted drilling system was still in the well.
The damaging mechanism was determined to be synthetic oil based mud compressed around the screen completion as well as the mud from the uncompleted horizontal lower hole being squeezed into the screens as the open hole gradually collapsed with time. A Coiled tubing (CT) intervention was carried out in late 2006 with solvents and multiple attempts with an acidic nano wash solvent system, this was not successful in restoring well productivity.
In 2007 BP chose to use an advanced chelate based barite/carbonate dissolver system behind a proprietary pre-flush system in an attempt to recover well productivity. Four operations have now been performed since September 2007 without CT, all as simple bull head operations. As a result of these treatments the well productivity (PI) has increased from 1.5 up to 12 blpd/psi. Current well rates are between 4000 to 6000 blpd depending on well stability and slugging caused by increasing water cuts.
Potential Increase of Formation Damage at Horizontal Wells as a Result of Changing Dynamic Filter Cake Properties with the Shear Rate
Authors: Dangou Mohamad , Chandler Howard 
Published: May 2009

Abstract
The invasion of drilling fluid filtrate into the region around the wellbore has long been recognized as one of the major factors contributing to damaging the reservoir formation. The volume of filtrate has a significant effect on the degree of damage, which is usually evaluated in API or HPHT static filtrate. Basically, filtration volume is a function of filter cake implementation, filtrate character, wellbore conditions and formation parameters. Under static conditions, as filtration proceeds a filter cake is formed and its solid content represents the particle size distribution of the whole drilling fluid. Under dynamic conditions, filter cake deposition mechanisms differ from those under static conditions due to the influence of hydrodynamic forces caused by drilling fluids flow. Consequently, the constitution of the dynamic filter cake is varies from that formed under static conditions, giving it different characteristics and filtration behaviour.
The scope of this study was to investigate the influence of the shear rate applied to the cake surface during dynamic filter cake deposition, on the filter cake constituents and dynamic filtration behaviour along horizontal wells. Extensive dynamic filtration experiments were conducted to test the filter cake and filtration parameters at the equilibrium dynamic stage. Three muddles of three different particle size distributions of Calcium Carbonate water-based drilling fluids were tested at different shear rates up to 400 sec-1.
The experimental results showed significant variations in dynamic filter cake parameters and filtration behaviour under different shear rates applied to the horizontal cake surface. Dynamic cake constituents and behaviour were also seen to differ from those of cakes formed under static conditions and one state cannot be taken to represent the other. Moreover, a critical value of shear rate can be detected from the dynamic cake parameters. The results also clearly demonstrated that a better cake quality was obtained at high shear rate values and a poor cake quality at low shear rates
First Regional Selective Packerless Acid-Fracture Stimulation With Coiled Tubing: A Documented Case History From Saudi Arabia
Authors: Sierra Leopoldo , Bustin Robert 
Published: May 2009

Abstract
A review of the stimulation methods used in the Hanifa formation (primarily a combination of diesel-emulsified acid/visco-elastic diverting systems) performed during the first two quarters of 2005 revealed that while initial post-stimulation vertical or deviated well-performance was typically improved, it was also short-lived (Surjaatmadja et al. 2001; Surjaatmadja et al. 2001; Surjaatmadja et al. 2002). All the wells exhibited a gradual loss in productivity after the stimulation treatments. Furthermore, in horizontal wells, the problem was aggravated because there was not enough control of acid placement over long openhole carbonate intervals where permeability or damage contrast existed; requiring a deeper matrix stimulation.
Exploring improved methods for stimulation, a multidisciplinary team composed of Saudi Aramco and service-company representatives were brought together to review various stimulation methods. After looking at conventional hydraulic-fracturing as a method of deeper-formation stimulation than matrix acidizing, it was concluded that over the long open-wellbore intervals, there would not be sufficient control of fracture placement, fracture growth and propagation, and interaction with the natural fracturing present in the Hanifa. Additionally, the typical Hanifa completion strings have completion size restrictions which limit the options for rigless stimulations.
After the review of several options, including coiled tubing (CT) proppant fracs, and stimulation using multiple and discrete mechanical-isolation devices like plugs or packers, the team selected the packerless selective acid fracture (PLSAF) stimulation using CT as the stimulation method most desirable for the limitations intrinsic to the Hanifa formation for the following reasons:
PLSAF with CT offers control of fracture placement in an openhole environment. PLSAF can achieve multiple treatments without mechanical isolation. PLSAF can provide moderately deep, controlled fractures with reduced risk to connect the generated fracture with the water sources.
PLSAF was applied successfully in one well during the third quarter of 2005, where ten selective acid fractures were placed along the openhole section. This paper presents the long-term evaluation and benefits of the first regional application of the PLSAF in Saudi Arabia.
Successful Field Application of a High-Temperature Conformance Polymer in Mexico
Authors: Mercado Modesto , Acuna Juan Carlos , Vasquez Julio , Caballero Carlos , Soriano Eduardo 
Published: May 2009

Abstract
Conformance-polymer systems have been successfully applied for many years to control undesired water production from hydrocarbon wells. However, currently available polymers present a number of limitations for high-temperature wells (&gt;250°F) in terms of providing longer gelation times and acceptable thermal stability. This paper presents the successful field implementation of an organically crosslinked polymer (OCP) for high-temperature applications in southern Mexico.
The OCP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneamine (PEI). To date, more than 450 jobs have been performed with the OCP system around the world to address conformance problems, such as water coning/cresting, high-permeability streaks, gravel pack isolation, fracture shutoff, and/or casing-leak repair. Originally, the OCP system had a limited working temperature range from 100° to 250°F. The upper placement temperature of the system was ~250°F because, above this temperature, pumping times were too short. A recently developed carbonate retarder allows reasonable placement times up to 350°F, without the need for cooling down the formation to obtain enough pumping time. The retarder is not detrimental to the thermal stability of the system.
An overview of case histories that used OCP in southern Mexico is presented in this paper. In addition, the development results of the high-temperature conformance polymer are discussed in terms of (1) gelation-time measurement and (2) effectiveness to limit permeability to water and thermal stability in sandpack flow tests at elevated temperatures. To date, more than 70 jobs have been successfully performed worldwide with the OCP at temperatures higher than 250°F.
Horizontal Well Deliverability with Turbulence Effects
Authors: Wang Xiuli , Economides Michael J. 
Published: May 2009

Abstract
It is well known that in higher-permeability natural gas reservoirs turbulence, at times referred to as non-Darcy effects, may become the dominant influence on production. For vertical wells turbulence has been relatively well understood, deliverability equations have been adjusted to account for the phenomenon and, correlations have been presented a long time ago. Furthermore, field-testing techniques have been established to obtain the non-Darcy coefficient.
Surprisingly, similar work has not been done for horizontal wells. One of the reasons is that horizontal wells have been the completion of choice in North America primarily for very low permeability reservoirs where turbulence effects are of no consequence.
However, as the international petroleum industry starts looking at high-permeability gas reservoirs, turbulence effects in horizontal wells can no longer be ignored. Past work on the subject has been sketchy and in the one or two literature sources where it was addressed, the calculations are demonstrably wrong, not taking into account the crucial near-well effects. Also, quite important is that the few turbulence correlations used in the past, for some unexplainable reason have ignored the porosity.
We present here appropriate correlations to account for turbulence effects in horizontal wells and show that while horizontal wells, even with turbulence, provide considerably higher performance than vertical wells, the reduction from ideal expectations can be substantial. For example, at a permeability of 100 md, while for vertical wells the reduction between real and ideal production may approach 40%, for horizontal wells, it may approach 30%. The influence of porosity is considerable and can account for another 30% deviation among reasonable porosity values
We finally offer a large range of parametric studies that involve reservoir thickness, permeability anisotropy and horizontal well length. Turbulence effects have a tendency to reduce the expected beneficial ideal effects from longer wells or permeability isotropy because of the implicit "suicide" effects deriving from higher production rates.
Case Study: Water Shut-off Mechanism in Small, Remote Platform-Process & Challenge
Authors: Noordin F. M. , Razak M. H. A. , Ismail M. 
Published: May 2009

Abstract
Malong is part of an integrated marginal field developed in 1999 called MASA. Hydrocarbon is evacuated to a nearby Floating Production, Storage and Offloading (FPSO) facility for export. Its produced water system is currently being used up to its maximum design limit and hindering additional oil production.
Malong main reservoir J2 contributes about 97% of the total production. Currently, 7 wells are producing at 7.7 kbopd with average water cut of 70 percent. 88 percent of 18 kbwpd comes from 5 deviated wells while the rest is from 2 horizontal wells. J2 is a water injected reservoir with moderate to strong aquifer. This high permeability sand is distributed fairly well across the field and is subdivided into upper and lower lobes.
A comprehensive diagnostic of water flow entry mechanisms begins with compilation of critical information such as geological and reservoir data, production and injection data, cased hole data and well history. Subsequently, several analytical techniques such as material balance analysis, water control diagnostic plot, bubble maps and nodal analysis are applied.
The water production mechanisms are primarily dynamic contact movement due to production and possibly accompanied by flow behind casing. In all the wells, the lower lobe is mostly flushed leaving some oil from upper lobe only. Screening of suitable water shut-off methods gets complex considering tubing integrity issue, i.e. multiple tubing leaks, poor cement bond and possible deep invasion due to high permeability formation.
Detail evaluation is performed to weigh the pros and cons of mechanical type (cement squeeze) and chemical type (polymer gel). Finally, polymer gel is selected on the basis of less operational risk, controlled depth of invasion and easier removal. Additionally, coil tubing with packer is selected as the deployment method to ensure accurate placement of gel and to evade chemical loss through leaks.
The Optimum Injection Rate for Wormhole Propagation: Myth or Reality?
Authors: Glasbergen Gerard , Kalia Nitika , Talbot Malcolm 
Published: May 2009

Abstract
The success in matrix acidizing carbonate-formations depends entirely on the ability to create long wormholes that bypass the damaged near-wellbore region. Recently, much work has been performed to understand the wormhole propagation. This has led to various criteria and models to optimize matrix-acid treatment design for volumes, fluids, and flow rates. In many publications, the existence of an optimum flow rate for wormhole propagation has been described and efforts have been made to design treatments around these criteria.
This paper will discuss several of the criteria and models that can be used to determine the optimum flow rate in both radial and linear flow and will introduce a new and simple criterion for both radial and linear flow that is based on diffusivity, reactivity, porosity, and surface area. Most of the criteria have been developed based on laboratory results or simulations in controlled and idealized environments.
Under field conditions, many additional factors must be considered. Because of certain parameters such as significant heterogeneities in the formation, uncertainties in formation data, uncertainties in fluid placement, and operational constraints, the environment is neither controlled nor ideal. This paper will discuss the impact of these field conditions on the criteria and models to determine the optimum injection rate and verify their validity under field conditions. Examples and a case history are included to emphasize the need for consideration of these parameters. In addition, constraints are given to the validity of the criteria for the optimum flow rate under field conditions. This paper will further discuss the best practices and recommendations for cases where these constraints cannot be easily met or in cases where the data is uncertain.
Water and Sand Control Through Linear-Gel Frac Pack and Relative Permeability Modifier Techniques: Case Histories From the Casanare Basin, Colombia
Authors: Escobar V. , Rodriguez L. , Zambrano P. , Martinez O. 
Published: May 2009

Abstract
The C7 reservoir, located in Casanare Basin, not only exhibits serious formation consolidation problems, but the producing zone is also close to the oil/water contact. Most of the workover interventions have been focused on sand- and water-production issues. A solution developed to obtain hydrocarbon production that combines sand-control and water-control techniques, without additional services to clean the sand or change the production pump, is presented in this paper.
Numerous methods for this purpose exist in the industry, such as mechanical sand control methods, chemical treatments, and combinations of both. These are typically applied according to best practices with consideration of the associated costs.
The sand-control technique presented in this paper has been applied for three consecutive years in the area of Casanare, Colombia and has proven to be successful. This technique consists of pumping linear gel at high rates to place the proppant into the formation; in some cases, up to 40 sacks/ft (experiences in other regions mention 3.5 sacks/ft). In some cases, because of the proximity of the water, it was decided not to fracture to prevent the influx of water.
To increase the amount of proppant placed in the formation, a combination of two techniques, which have each proven to be successful individually, has been implemented. These techniques are: (1) use of a relative permeability modifier (RPM) to control the water influx and (2) high-rate pumping of linear gel to place proppant.
The combination of the RPM treatment and sand-control technologies designed for each particular area has set a new standard for sand-control operations in the area.
Multilateral System Allowing 100 Level 5 Laterals Drilled Simultaneously
Authors: Freyer Rune , Kristiansen Tron , Madland Merete Vadla , Omdal Edvard , Omdal Øyvind 
Published: May 2009

Abstract
New completion techniques improving recovery, production rates and reducing cost and complexity are always looked for in the oil and gas industry. This paper is presenting a new concept where 100's of small level 5 laterals can be drilled simultaneously into the formation around a main wellbore. This paper presents the main concept as well as some preliminary results from qualifying the system for service in a high porosity very weak chalk reservoir. The qualification of the system is addressing three main aspects, the ability to jet a 12 meter long and 5–10mm diameter lateral, the ability to produce in high porosity weak chalk without loss of production, and simulation of production that is at least as good as or better than existing technologies like propped fractured horizontal wells, acid fractured horizontal wells and different types of openhole completions with and without liners. The experiments indicate that the system is able to achieve the results we are looking for.