Horizontal wellbores can present unique problems during water and gas shutoff operations. The primary challenges include the extended length of many horizontal wells, which could be outside the reach of coiled tubing (CT), and the fact that many are completed with open holes, gravel packs, or slotted liners. With gravel pack and slotted liner completions, it can be extremely difficult, if not impossible, to obtain complete zonal isolation. Even when the offending water or gas producing zones are clearly demarcated from the producing zones, chemical remediation remains arduous. Mechanical plugs can be set inside gravel pack screens or slotted liners and a chemical sealant can be pumped into this isolated internal section. However, it is difficult to limit fluid flow in the outer annular space. Because most chemical sealants are designed to have relatively low viscosity, they tend to slump to the low side of the wellbore, either inside or outside of this isolated section. Consequently, the water and/or gas zones are not uniformly exposed to the treatment, which could result in an incomplete seal. Because more horizontal wells are being drilled, water/gas shutoff systems are necessary for these types of completions. An ideal sealant system would exhibit flow properties facilitating pumping and placement while, immediately upon placement in the desired location, resist slumping by behaving as a thick paste. This paper presents three systems designed to address the challenges associated with treatment of zones within horizontal wellbores. The objective was to develop sealant systems that would not slump upon placement and subsequently undergo polymerization, crosslinking, or setting and provide lasting seals to prevent water/gas flow. The fluids discussed include polymeric and monomeric gels and a Sorel cement based system, which additionally contains additives to provide slump resistant properties. The chemistries that impart the slump resistant properties are discussed. In addition, laboratory data is presented to include slump measurements, gelation times, and flow resistance measurements.

Success in matrix acid stimulation of carbonate formations depends largely on the acid distribution and the created wormhole length. Treatment design is still as much art as science, especially where field experience is used to quantify the design parameters for candidate wells. However, each well is different, and this generic approach for treatment design can result in under- or over-treating. Another challenge for long horizontal well matrix acidizing is the distribution of acids throughout a long horizontal well. Recently, controlling the perforation density and distribution has been implemented in long horizontal well matrix acidizing and proved successful in improving well productivity. This approach basically involved pumping acid through a perforated work string inside a large open-hole area. The acid distribution with limited entry into the surrounding a horizontal well is mainly controlled by perforation distribution around the work string. In this paper, a fluid placement simulator is used to study the key parameters in optimal acid distribution with this novel limited-entry technique in long horizontal well matrix acidizing. The algorithm is based on a 2-D radial flow system that iterates time to quantify wormhole propagation and injection rate. Wormhole velocity is calculated by a laboratory empirical model that depends on two parameters measured from core flow testing. Therefore, the algorithm captures the essential physics and chemistry of the acid reaction in a carbonate porous medium. Also, this model includes such effects as multiple formation layers with independent formation parameters and allows for modeling zonal coverage, zone skin factor, and total skin factor. The main difference in terms of the improvement of formation damage from both openhole and this limited-entry completion is investigated. The developed algorithm is a relatively simple tool that can be used by field engineers to design and optimize an acid treatment, addressing key questions such as: What type of acid and what strength should be used? What are the optimum acid volume and pump rate? What are the best diversion method and staging design? This paper demonstrates the key issues related to the interaction between the wormhole model and zonal coverage. In addition, different scenarios and a field case example are presented and discussed.

The Troll field in Norway is a large gas field with a thin oil column. The thin oil column requires the wells to be drilled as long horizontal oil producers and development of the field has relied entirely on water based drilling fluids. As the pressure in the reservoir is depleting there is a requirement to reduce the density of the drilling fluid used to avoid losses. The latest development that is described in this paper is the design and implementation of a reservoir drill-in fluid with a maximum density of 1,07 SG, which at the same time maintains all the technical requirements necessary to avoid formation damage. The laboratory evaluation and verification was performed together with the operator to ensure no operational problems arose from changing to a new system. New technology was introduced to allow for clay inhibition without the use of salt to reduce the density of the base fluid. Bridging was optimized to match the requirements for the high permeability reservoir with minimum concentrations of solids. Product selection was driven by the need to ensure minimum formation damage. The initial field trial and the resulting implementation on subsequent wells and different rigs are described. The difference in performance related to other types drilling fluid systems is discussed. In addition, the effect of the differences in solids control equipment and storage capacity on different rigs is evaluated.

Hydraulic fracturing has become a common completion treatment or stimulation treatment for horizontal wells; however, effectiveness of these treatments, in terms of improved production, is difficult to predict. One reason for uncertain production results is poor fracture initiation in the reservoir, which can be caused by drilling-induced damage or a formation's natural resistance to breakage. Several approaches have been attempted to solve this problem and provide a better return on completion investment. One approach that has achieved strong initial results is the use of dipole sonic logs to determine closure stress. From closure stress, formation breakdown pressures can be determined, which are used to design more effective treatments and place them more efficiently in the well and reservoir, where breakdown pressures are lower. This paper presents research to validate this approach. Two wells were selected in the same area and geologic setting. The first was completed using standard processes for this asset. A dipole sonic log was run in the horizontal wellbore before beginning the completion. Results from the sonic log were compared to the fracture treatments after the fact. In a second vertical pilot well, information was acquired, including elemental capture, dipole sonic, and nuclear magnetic resonance, with the objective of determining rock texture, vertical and horizontal rock mechanical properties, effective porosity, and permeability. A dipole sonic was then run through the horizontal section of this second well to determine anisotropy. This knowledge was used to select perforation and stage points in the horizontal well and design fracture treatments. Two additional reservoirs are included in this paper where dipole sonic logs were run only in the horizontal cased hole but reference nearby pilot holes. Results from all cases were positive; therefore, it is believed that this technique can be useful in any reservoir.

Maximum reservoir contact and extended reach wells have been widely used to maximize the well productivity. The horizontal section could be 6000 ft or more in those wells, which make the damage caused by the drilling fluid varied from one section to another in the long horizontal section. The process of diversion of the stimulation fluid in carbonate wells with the same features has been performed using Viscoelastic surfactant (VES) and polymers based hydrochloric acids. In sandstone wells we cannot use either VES or polymers because there is no enough calcite to react with these fluids to produce the gel diverting materials. Also, VES could be adsorbed on the sandstone surface and cause more damage to the formation, and the use of HCl in sandstone formations has been proved to be more damaging than removing the damage. In this paper we will introduce a smart fluid that can be used to remove the damage caused by calcium carbonated weighted drilling fluid from the maximum reservoir contact (MRC) and extended reach wells without adding any gelling materials. This fluid will react with carbonates in the sandstone formation and will produce high viscosity that will divert the flow through the less permeable part in the horizontal sections. The proposed fluid is HEDTA (hydroxyl ethylene diamine tri acetic acid). Sandstone cores were used in the coreflooding experiments, and the stimulation fluid viscosity will be measured before and after the flooding. Parallel coreflooding technique was used to confirm the diversion ability of this chemical through two sandstone cores with different permeabilities. The experimental results showed that the viscosity of the stimulation fluid increases at least 3 times after the treatment of the sandstone cores and the parallel coreflooding showed a good ability of diversion for the fluid. The experimental results were used to describe the process of diversion using this fluid mathematically in this. HEDTA chelating agent showed good ability to remove the damage caused by drilling fluid from different permeability contrast set of cores.

Sanding is vitally a serious problem during heavy-oil production from unconsolidated reservoirs. In order to effective sand control and high well production, various sand exclusion technologies are used for horizontal well completion, especially, the open-hole gravel pack (OHGP) has been widely used. So it is critical to quantitatively evaluate permeability impairment because of sand particulates migration and plugging in gravel-packed layer, and it is also important to predict horizontal well productivity. In this paper, we have developed one numerical model of permeability impairment based on the previous experimental observation. This numerical model considers the liquid-solid fluid flow process, and sand particles depositing and plugging in gravel-packed layer. The numerical simulation results of permeability impairment at different sand volume fraction, fluid viscosity and sand radius are given, and the simulated results are in good agreement with the previous experimental results. Integrating the permeability impairment model a new model to predict productivity of gravel-packed horizontal well has been proposed. The proposed model couples reservoir inflow and seepage in gravel layer, and it can quantitatively evaluate the damage of gravel layer and predict well productivity performance. The numerical simulation of real-world scenarios investigates that it is more accurate than previous models, and it is very easy to use. 1 Introduction Recent years with reduction of conventional reservoir, the unconventional reservoirs (i.e. heavy-oil reservoir, low-permeable reservoirs, and fractural reservoirs) have become significant in oil and gas development, especially the heavy-oil reservoir has been main part of unconventional reservoir (Z. et al. 2004; Mohammadi et al. 2012). Because of high viscosity and unconsolidated condition, sanding is the main problem affecting the development of heavy-oil reservoir. Rock failure surrounding wellbore is prone to happen because of weak bonding strength, resulting in large mass of sanding. The sand production in well will not only lead to serious abrasion wear on down-hole and surface equipment, even well sandup or sand burial accident, but also decrease of recovery efficiency and oil well abandonment (Tian et al. 2005; Li et al. 2004; Shao et al. 2004; Li et al. 2011; Li et al. 2012). Sand production in oil-producing wells is usually related to the following two mechanisms: (1) Mechanical instabilities and localized failure; (2) Hydro-mechanical instabilities due (Veeken et al 1991). Many studies have been performed in the past on different aspects of sand production. However, they have mainly concentrated on finding effective methods to avoid sand production because of the high operating costs involved in handling and disposing of produced sand (Travis et al. 2004; Brígida et al. 2011). In order to ensure safe operation of facilities, reduce formation damage and enhance productivity, some of the most common sand exclusion techniques used for horizontal completions include: the open-hole gravel pack (OHGP), stand-alone screens (SAS) and expandable sand screen (ESS). Gravel packing sand control is widely used in oilfield for the existing advantages, such as good sand control effect and little impact on productivity (Dong et al. 2009, 2010). Sand migration and plug are important factors affecting the validity length of gravel packed well. Therefore, it is of great significance to evaluate the influence of formation sand particles migration on gravel layer permeability and recognize the plugging mechanism clearly, which is important to predict productivity accurately and improve the effectiveness of sand control.

The knowledge of damage profile in horizontal wells is the key to designing the appropriate treatment volume to restore or improve their productivities. The elliptical (conic) damage profile associated with horizontal well is known but review of industry-wide applications by different Operators shows no corresponding uniform correlation between the damage profile and actual treatment volumes that have been applied. The result of this inadequacy has often led to sub-optimal post stimulation performances due to either partial damage removal or formation deconsolidation as a result of little or too much acid volumes across the damaged zones that could lead to poor coverage or over-dose with attendant incomplete damage removal or secondary precipitates respectively. Funds spent on stimulating horizontal wells estimated at average of USD 0.5mln/well did not yield the expected rewards as the stimulation gains are mostly short-lived due to wrong volume design and application. The problem highlighted above led to the emergence of this engineering model based on the complete knowledge of elliptical horizontal damage profile usually associated with horizontal completions and is presented for improved stimulation solution to the removal of damage in horizontal wells. The approach offers true stimulation in cost effective manner by applying only the right acid volume in the right zone of interest. The development of the horizontal well stimulation model from the first principle and presentation of easy-to-read table and charts for specific range of well parameters (damage radius, porosity, wellbore radius and drain-hole length/diameter) versus treatment volumes, field applications guide, limitations and costs/treatment benefits are the output derivable from this innovative work. The benefit of this emerging technology includes; reduction in cost of chemical for well treatment, true stimulation of damaged near-wellbore region and improved performance, minimal contact of acid system to downhole tubular and overall cost efficiency estimated at 50% savings when compared with existing approach that uses about 200% of the required acid volume.

Formation damage sometimes has a significant impact on well productivity or injectivity. Much of the work undertaken to mitigate against formation damage serves to qualify the impact of damage and for example, determine the least damaging introduced fluids. Whilst qualification is important, quantification of damage impact is a much greater prize. Taking advantage of increased computational power and speed, Computational Fluid Dynamics (CFD) has been applied in the last five years to numerically model and quantify flow restriction in wells and the near wellbore ( Byrne et al 2009 ). This process enables better prediction of the real impact of formation damage on well productivity. The process has been applied to many real fields and wells and in this paper we present some of the latest revelations on the impact of formation damage on well performance. In order to illustrate the simplicity of the process a sensitivity analysis of typical formation damage restrictions has been applied. This demonstrates the impact of different formation damage quantities and depths on different well trajectories and lengths in the same reservoir. In some cases the impact of damage that could be classed as "severe" in a laboratory test has little impact on eventual well productivity. In others the damage has a profound impact on well performance. With the obvious caveat that every well is different, we propose some consistent guidelines on the impact of damage based on our numerical modelling work. Modelling of this kind does not reduce the necessity to understand or simulate damage, instead it enables focus where formation damage has greatest impact and creates a greater awareness of the importance of damage to our industry. Through increasing use of appropriate modelling, uncertainty is reduced and better wells can be drilled and completed.

Due to usual higher oil and gas production, high permeable reservoirs are considered to be forgiving and to be able to hold up very well against formation damage induced by any solids and liquids, so these reservoirs have not deserved a fair share of that attention. In fact, any formation damage can inevitably alter the permeability of the porous media and adversely affect oil recovery to different degrees, and the damage is more deadly to horizontal well. Triassic reservoir with the maximum permeability of more than 2 Darcy and the maximum throat sizes of more than 100 μm in the Tarim Basin provides us with a perfect example. Horizontal well is the key technique to increase oil production in this reservoir. However, after completion, horizontal wells can not produce through natural power or gas-lift, and did not present the advantages of increasing production compared with vertical wells. The results of granularity analysis and dynamic damage evaluation experiments present that the original drill-in fluids can not protect the reservoir with permeability of more than 100 mD, while the percentage of regain permeability is less than 50%. The drilling fluids were modified by adding fibrous bridging agents instead of common spherical bridging agents to rapidly form a tight plugging zone near the wellbore that efficiently seals the large pore throats. The dynamic filtration test and the analysis of mudcake through the FEI Quanta 450 environment scanning electron microscope (ESEM) showed that the optimized drill-in fluids can form tight filter cakes, plug the pore of reservoir effectively, and enhance the percentage of regain permeability of core samples up to 90%. After the application of the new drill-in fluids, horizontal wells are in high flowing production after completion, and the wellbore quality are also improved.

When performing matrix stimulation treatments, coiled tubing (CT) is a preferred placement technique due to the ability to spot fluid in front of the target zone(s). This method becomes a key solution when formation heterogeneities require a very selective fluid placement strategy. In today's industry, the most common approach is to design a treatment with volumes of stimulation and diverter fluids that are determined largely based on local practices. Often, it amounts to targeting a uniform stimulation, thus requiring a predefined amount of treatment fluid per length of total pay zone. That approach, although widely used and accepted, may not necessarily yield an optimum stimulation. We present an alternative technique that relies on the accurate quantification of fluid placement along the formation in order to define the respective volumes of stimulation and diverter fluids to be pumped. This method relies on the analysis of the distributed temperature sensing (DTS) data recorded by a fiber-optic line enclosed inside the CT and data processing through a fast interpretation algorithm to yield a zonal coverage profile. During a job, DTS data corresponding to the preflush can be used to estimate the initial placement distribution across the pay zone. This allows stimulation engineers to determine the best strategy for the subsequent well stimulation treatment, including fluid volumes and placement sequence. After every major pumping stage, a new DTS analysis assesses how the formation reacted to the treatment, improving placement strategy. This method has been used in multiple matrix stimulation treatments of injector and producer wells. The described innovative approach allows engineers to make more informed decisions between stages, optimizing fluid resources, fluid placement and, ultimately, stimulation effectiveness. It also leads to noteworthy advantages when designing new acidizing treatments, as companies can build on previous experience from similar wells and fields.

Unconventional reservoirs require an effective system of completion. A major difference between unconventional and conventional reservoirs is the plastic nature of the rock itself. Within a very short period of time, certain portions of the reservoir will flow, sealing off the productive mechanism and capacity of the formation. Complicating matters even more is the near universality of horizontal drilling in these reservoirs. Dipole sonic logs have been used for many years to establish rock mechanical properties for conventional formations. The use of Young's Modulus and Poisson's ratio in frac design is well established. This same relationship exists in the unconventional world, but the complication of plasticity in the formation makes the relationship more difficult to understand. Traditional twodimensional models have not been able to adequately identify intervals of the horizontal reservoir that could maintain the fracture treatment. The calculation of three-dimensional rock mechanical properties has been advanced as a way to overcome this difficulty. This paper presents the application of this advancement in unconventional reservoirs. This paper will also discuss the differences in two-dimensional and three-dimensional data and the effects of ignoring this information.

Displacing drilling mud with clear solids-free completion brine is one of the most critical steps during well completion. Drilling deeper below the mudline (25,000+ feet) and exploring deeper water depths requires critical evaluation of conventional displacement methods and testing procedures and leads to a more rigorous displacement scenario. Deep wells generally contain greater volumes of working fluid, larger diameter wellbores and drill strings, more feet of casing, and significantly increased surface area that require effective cleaning of mud residue and debris during the displacement process. Therefore, such wells typically require larger volumes of displacement spacers, enhanced pumping rates, and enhanced cleaning chemicals that tolerate substantial mud contamination while maintaining cleaning effectiveness. In order to properly design displacement spacer systems, these parameters must be incorporated into the evaluation and testing scenarios. This paper describes methods and processes that incorporate the key wellbore parameters, including temperature and density requirements, into the displacement spacer system in order to define the size of spacers, amount of cleaning chemical included in each spacer, number of spacers required, and test methods used to validate the displacement design for the target well. Case histories illustrate how to design and execute an efficient and effective displacement job and the cost savings involved when a displacement system is properly developed. Failure to complete properly the displacement process can lead to complications in subsequent completion and tool operations, and contribute to wellbore control issues. Furthermore, increased formation damage due to residual solids and time lost to resolve any issues can significantly increase the cost of the completion.

In the Danish Central Graben, the Lower Cretaceous reservoir contains significant in-place oil volumes. This formation historically has posed a real challenge to develop because of the extremely low permeability. The low permeability is compounded by the fact that the formation is soft, highly heterogeneous, and can have significant clay content in some areas. Although the Lower Cretaceous chalks represent a wide spread play in the central North Sea, there are no producing analogs. Thicker Lower Cretaceous reservoir sections in the Valdemar field have been successfully proppant fracture stimulated. Acid stimulation is preferred for the thinner sections; however, early attempts at matrix acid stimulation were very disappointing. Recently, the need to re-enter a well for maintenance allowed three zones to be selectively restimulated using improved execution techniques and a more appropriate acid formulation. Production increase following restimulation of this first well was very encouraging and the lessons learned were applied to a second well; this time a newly drilled well completed in the Tyra Lower Cretaceous reservoir. This paper summarizes the lessons learned, starting with a review of the previous acid stimulations. Wormhole testing with Lower Cretaceous core material provided important insight toward the selection of the most appropriate acid formulation. Computer modeling was used to determine the most effective perforation patterns, based upon variable formation characteristics along the long, horizontal wellbore. Treatment execution and monitoring included diagnostic injection tests and real-time calculations of acid coverage during the limited-entry perforated completions. The results of these two wells has been very encouraging and has opened up the possibility for continued testing of acid stimulation techniques in both the Valdemar and Tyra Lower Cretaceous reservoirs.

In the Middle East, extended reach horizontal wells (on the order of 25,000 feet of horizontal displacement) are commonly acid stimulated by jetting acid out of drill pipe. The acid is jetted onto the face of the openhole wellbore as the drill pipe is withdrawn from the well. The jetting action helps to remove the drilling fluid filter cake and promote the acid to penetrate into the formation and form wormholes to stimulate the well. However, with very long sections of wellbore open to flow, the acid placement and subsequent wormhole distribution and penetration depths are uncertain. We have modeled this process using a comprehensive model of acid placement and wormhole propagation in a horizontal well. We presume that the acid jetting tool removes the drilling mud filter cake, so that no filter cake exists between the end of the drill pipe and the toe of the well. Correspondingly, we assume that there is an intact, low-permeability filter cake on the borehole wall between the end of the drill pipe and the heel of the well. The drill pipe is modeled as being withdrawn from the well during the acid jetting treatment, as is done in practice. The acidizing simulator predicts the distribution of acid and the depths of wormholes formed as functions of time and position during the acid jetting treatment. The model shows that the acid jetting process as typically applied in these wells preferentially stimulates the toe region of the horizontal well. Comparisons of the simulation predictions with published data for acid jetting treatments in such wells showed good general agreement. Based on the simulation study, we present recommendations for improved acid jetting treatment procedures to improve the distribution of acid injected into the formation.

Acid stimulation for damage removal is performed when a well is expected to produce satisfactorily when the skin is approximately equal to one. Blindly flowing acid into the well is the easiest thing to do and is commonly performed when the exposure length of the well is relatively short (commonly done in vertical wells). However, as wellbore lengths become longer, this approach is not preferred because it can create massive enlargements to sections near the top of the formation and complications could occur, ranging from re-entry issues and lack of treatment coverage to wellbore collapse. Tubing-conveyed acid, mostly by coiled tubing (CT), would be the logical choice for acid placement because it evenly spreads the acid throughout the wellbore. Spotting acid throughout a long wellbore has been widely accepted as a viable solution for cleaning the surface of the wellbore. Using CT, acid washing is another common process that can improve stimulation without much additional expense. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by this acid-wash process increases the chemical reactivity of the acid at the desired locations. This paper discusses the implementation of an improvement to the process that uses specialized jetting mechanisms which position the jets closer to the target. This process also uses higher horsepower to provide higher jet-impact pressure onto the wellbore wall. This improvement provides several benefits, including effectively penetrating natural fractures and opening them while stimulating them. Moreover, at certain locations, larger fractures can also be created, which can result in even better production. Actual results of such stimulations are presented.

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. Introduction To The Harding Field The Harding Field, in Block 9/23b of the U.K. North Sea (Figure 1), consists of 2 main reservoirs (Central and South) developed with horizontal wells, and several satellite pools accessed via extended reach wells (Figure 2). The 2 main reservoirs currently contain 13 horizontal producers, 3 water injectors and in the central reservoir, a single gas injection well. Both main reservoirs are overlain by large gas caps so well location and production were carefully managed to minimize excessive gas production through gas coning. As aquifer support is negligible, the reservoir pressure is maintained via re-injection of the produced water supplemented by water from a shallow aquifer zone. The South reservoir has excellent static properties but the fluid quality is less favourable. The wells are all located in the Balder Formation which is a massive homogeneous sandstone up to 150 feet thick. It is poorly consolidated, with an estimated permeability of 8 to 10 Darcies, porosities of 32 to 35%, and a net to gross (NTG) of 93 to 95%. However, the viscous oil (23 ° API, 5 centipoise) leads to unfavourable mobility ratios which tend to promote coning. The wells are operated with low drawdown's (typically less than 20 psi) to minimize water and gas coning. It was possible to achieve this and still produce at high rates due to the very high productivity of the wells, which was often in the range of 500 to 1,200 blpd/psi. The Harding Field came on stream in April 1996 and the south reservoir was initially developed over a 2 year period with 3 horizontal producers and 1 horizontal water injector, all in the high quality NTG sand. Sidetracks of the original producers have occurred to improve reservoir recovery, the 3rd being the IS3 well which was drilled as a sidetrack from a multilateral producer which had watered out during late 2005. Multiple sidetracks of the IS3 well target eventually led to the well being named IS3x.

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. Introduction Horizontal-well completions in low- or moderate-permeability reservoirs have gained popularity in many regions of the world and especially in Saudi Arabia where short, medium, long, or extended-reach openhole completions were placed in the majority of the prospective carbonate formations. Under ideal conditions, horizontal completions reduce the number of wells drilled to effectively recover hydrocarbons from the formation. For lower-permeability reservoirs, or even moderate-permeability reservoirs with vertical-permeability anisotropy, the completions often dictate the drilling and completion of very long laterals, which will often increase the wellbore damage. The damage induced during the drilling and/or completion drastically affects the wells' productivity; stimulation or fracturing is a required step to reestablish or improve the productivity. The negative effect of the induced damage is notorious for the wells completed in the Hanifa formation (carbonate formation), where the damage drastically affects the flowing efficiency of the openhole horizontal wells.

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. Introduction Increasing productivity in conventional and tight reservoirs is commonly achieved by stimulation operations. Environmental and economic effects require complex logistical setups and often demand experimentation to achieve good productivity. Multilateral technology is an alternative to stimulation, and jetting laterals with acid or non- reactive fluids have become an increasingly employed alternative to stimulation in some fields. The most common systems utilize coiled tubing or hoses as the fluids deployment conduit (Rae et al, Cirigliano et al). Some systems can be employed in open hole, but if the motherbore is lined, any motherbore liner needs to be penetrated by jetting or milling holes. The jetting systems require intervention and only one lateral can be jetted at any time. The development of the Acid Needle jetting system started with the premise of making multiple small diameter laterals simultaneously to simplify operations and allow large numbers of laterals increasing reservoir contact. Intuitively a large number of laterals spaced out in the liner would create predictable and evenly distributed flow patterns increasing recovery of hydrocarbons significantly. The design parameters of the system were: Placement of laterals should be predictable and controlled by spacing out liner completion items It must not require intervention and the only operation must be pumping small volumes of commonly available fluids from surface Laterals should be uncemented, connected to the motherbore, lined and enable formation solids control (sand screen) Not require specialist service personnel on rigsite Be extendable to cover a broad range of wells and formations Be no restriction for intervention

Abstract The Rita gas field was the first dual lateral well aimed at carboniferous reservoirs drilled in the UK Southern North Sea. This method enabled both the East and West fault segments of the field to be produced from the same upper well bore, thus reducing drilling costs and improving field economics. An invert emulsion drilling fluid was chosen for this field application due to the risk of shale instability over the long horizontal sections of each wellbore. The West segment was drilled and suspended with a whipstock placed above the sand screen completion. The positioning of this whipstock would not allow for re-entry, making remediation of the West lateral impractical. A remediation treatment for this leg was required as the planned suspension fluid was an invert emulsion system that would be in contact with the completion screens and reservoir for more than a month whilst the East leg was drilled and completed. The chosen suspension fluid in the East leg removed the requirement for remediation with enhanced well productivity. This paper describes the design and testing of the reservoir drilling and suspension/completion fluids that were used on this multi-lateral project to minimise drilling time and maximise productivity. Introduction The well described in this paper was a complicated design and consisted of a dual lateral to produce gas from two unconnected reservoirs. The Rita well (44/22–12) was spudded in early July 2008. The first (West) leg of the well had a TD of over 17,000 ft with a 6" horizontal section of over 2,700 ft. After the lower completion was run in the first leg a whipstock was set to enable drilling of the second (East) leg. The East leg had a TD of 15,600 ft and a 6" horizontal section of over 2000 ft. The plan was to suspend the first leg for a period of time that might exceed 2 months to allow for the drilling of the second leg and the running and installing the novel completion. This industry has experienced lower than expected production rates from wells which have been suspended for long periods with oil-based, solids-laden fluids before a clean up has been initiated. This raised the question of what type of fluid to leave below the whipstock, as re-entry to this leg for clean-up or well remediation was not economically feasible if production was lower than expected. Due to the diametrically opposed shape of the well, with long horizontal sections the drilling team was strongly in favour of using an oil-based reservoir drill in fluid (OBRDIF). This fluid would give a stable wellbore and provide a low friction co-efficient for drilling and running the completion assemblies. Using OBRDIF would reduce the risk of hole instability and minimise non-productive time. However if OBRDIF was used in the drilling phase, it would mean that a solids-laden invert emulsion would be left in the hole when the first leg was suspended with the sand screens below the whipstock. This presented several risks. The fluid would require fine screening to prevent blocking of the completion equipment with drill solids. Also, there was a risk that the solid particles in the suspension fluid would agglomerate as the fluid remained static for an extended period. If agglomeration did occur, these solids would probably not pass through the mesh of the completion screens and could potentially reduce their conductance. The size and concentration of the solids in the suspension fluid were recognised as areas of concern that should be addressed to ensure maximum productivity of this well.

Abstract Sand production in unconsolidated formations has brought heavy injury for the oil and gas industry around the world. Million dollars have been invested in sand control techniques. Among the several sand control systems existing, Open Hole Gravel Pack (OHGP) is the one adopted for horizontal well completions in the offshore Brazilian fields. With the experience in the development of such fields, some assets start to consider the adoption of less conservative sand control strategies, such as the use of stand alone premium screens (SAS). The present work proposes a methodology for evaluating the impact of the sand control technique in the productivity or injectivity of a horizontal well. Several parameters, such as damage rate (DR) and productivity or injectivity index per horizontal effective length (PI/Lef) were used to compare similar wells equipped with different sand control techniques. The main goal of the study is to address the following questions: There is any formation damage due to the gravel pack during production lifetime of a well? The wells equipped with stand alone screen exhibit formation damage? Wells equipped with OHGP have the same performance when compared with wells equipped with SAS? Stand alone completion is a good alternative path for multilateral and extend reach wells? Introduction Maximizing well productivity / injectivity is pursued by many ways: through sand management (Mathis 2003, Oyeneyin et al, 2005), sand and water management (Nguyen et al, 2007), by using suitable completion fluids (Milhone, 1983) to prevent well completion damage, by ICD screens implementation (Fernandes et al, 2006; Wibawa et al, 2008) or during drilling operations using sophisticated tools in horizontal well placement technology (Altman et al, 2007). The specific topic of this paper deals with the impact of sand control strategy on well completion efficiency. Different operators have different views on the criteria of investing on sand control techniques or sand management in onshore environments. On offshore scenarios, especially in deepwaters, it seems that there is a common sense that sand production is a major issue and should be avoided. All the efforts should be spent to minimize equipment erosion and production interruptions to clean surface separation systems. PETROBRAS defined that all offshore wells in non consolidated sandstones should be equipped with adequate sand control techniques. Perforation of cased and cemented horizontal sections did not appear as an economical alternative and, consequently, open hole completion with sand control techniques was the path to follow for horizontal wells. Tiffin et al (1998) defined a criterion for screen type selection, while Bennett et al (2000) stated that, for offshore wells with water depths greater than 500 m, openhole gravel packs with and premium screens are recommended. This guideline is based on the concept that, for long life cycle wells, additional barriers to prevent production interruption and avoid or postpone workover jobs should be considered. The first horizontal wells in unconsolidated sands in Campos Basin were completed with Stand-Alone-Syntherized screens. At that time the industry were not capable to support the requirement of an additional barrier for sand control in open hole horizontal sections. Motivated by the increasing demand for the activity and by failures in the wells equipped with syntherized screens, the service companies rapidly developed more reliable sand control solutions for the offshore environments: premium screens and gravel pack tools were soon available and the strategy proposed by Bennett was promptly adopted as a global criterion for offshore fields in PETROBRAS.