The South Arne Field, located in the Danish sector of the North Sea, has been producing oil and gas since 1999 with an active waterflood since 2000. Producers and injectors are primarily horizontal with sliding sleeve completions targeting both the Ekofisk and Tor chalk formations. South Arne is currently in exploitation modewith a new (Phase III) development program. Phase III includes two new platform installations, a two-kilometer umbilical bundle and an eleven-well drilling program targeting the northern extension of the field. This paper discusses the first five Phase III wells, focusing on stimulation design, lessons learned from the fluid testing, experiences, and the continuous improvement of the operational execution process. New producer and injector stimulation designs are generally based on a pad-acid procedure in which a cross-linked gel pad is followed by an in-situ cross-linked hydrochloric (HCl) acid treatment, to create viscosity contrast for diversion and differential acid fracture etching for sustained conductivity. The acid fracture treatment is then followed by a closed fracture acidizing (CFA) step to enhance near-wellbore fracture conductivity. For wells completed in zones that have the potential of short-circuiting to neighboring wells, lower rate and smaller volume HCl matrix treatments are pumped. The Phase III stimulations to date have been conducted through ball drop sliding sleeves, with the number of zones ranging from 10 to 14. Establishing Phase III success has required extensive QA/QC testing to optimize the stimulation fluid systems and, in particular, the acid corrosion inhibition program. Use of real-time bottom-hole temperature measurements during stimulation treatments has enabled optimization of corrosion inhibitor loadings, resulting in both an environmental benefit and financial savings. The stimulation treatments are performed simultaneously with drilling operations, therefore extensive work was required to ensure that stimulation and drilling activities are safely executed without interference. Both platforms were initially designed to optimize productive time during stimulation operations, however as the project evolved, thorough risk evaluations pointed to the need to modify operating plans. Rigorous marine and vessel audits were performed to ensure that stimulation vessels could operate safely and effectively from both a marine and stimulation job execution standpoint. The design, testing and advance preparation for the South Arne Phase III program has resulted in safe and effective treatment execution.

Over the years, sandstone acidizing has experienced low success rate. This makes it essential to develop a systematic method for selecting the optimum hydrofluoric acid (HF) concentration, which can achieve the highest possible permeability enhancement. Field experience and experimental studies show the significance of HF acid concentration in controlling the outcome of the treatment: adding too much HF acid will result in secondary and tertiary reactions damaging the reservoir while the use of low concentrations of HF will result in insufficient dissolution. The objective of this study is to investigate the effect of HF acid concentration and design a systematic method for designing sandstone-acidizing treatments. Experimental work was designed to investigate the effect of the HF acid concentration, and identify the optimum concentration for different sandstone formations. Two types of sandstone cores were used in this study: Grey Berea which is characterized by low carbonate content (3 wt%), and Bandera which has a high carbonate content (16 wt%) and high content of troublesome minerals (10 wt% illite). Coreflood experiments were performed on 6 in. cores with 1.5 in. diameter. Temperatures of 280 and 325°F were used for the experiments to address the moderate and high temperature applications. HF acid concentrations varied from 0 to 3 wt% HF. Optimum concentrations were selected based on the ratio of permeability improvement. Inductively coupled plasma (ICP) was used to measure the concentrations of key ions in core effluent. The experimental results proved the relationship between the acid concentration and mineral content. At the temperature of 280°F, Grey Berea cores, with clay content of 8 wt% and 3 wt% feldspars, the HF concentration of 1.5 wt% was able to achieve the best results. For the Bandera cores, which have a clay content of 14 wt% (10 wt% illite, 1 wt% chlorite, 2 wt% kaolinite) and 12 wt% feldspars, the acid that achieved the best results contained 1 wt% HF. When temperatures were increased to 325°F, permeability enhancement was significantly decreased while the optimum concentration remained fairly at the same HF concentration. This proves that the optimum acid concentration is independent on the temperature, but for high temperatures (>300°F) retarded acids should be considered. This work introduces the concept of designing acid treatments as a function of the mineral content. The optimum concentration of the HF was proven to adopt an inverse relationship with the mineral concentration. The proposed relationship can be used to determine the optimum acid concentration required for sandstone stimulation.

Low productivity indices are observed in many moderate-to low-permeability coal bed methane (CBM) and shale gas (SG) reservoirs due to low aperture and poor connectivity of natural cleats. A method is proposed for injection of graded proppant particles into a cleat system below the fracturing pressure to keep coal cleats and shale fractures open during water-gas production. Graded proppant injection in CBM and SG reservoirs can: stimulate a stress sensitive cleat system below the fracturing pressure; enhance fracturing treatment by invading cleats, lowering fluid leak-off, and maintaining aperture during production; and provide a periodic or remedial treatment to counter effective stress on the cleats improving production by maintaining cleat aperture. Laboratory tests on bituminous coal core flooding with water under increasing pore pressure with graded proppant injection at the maximum pore pressure (minimum effective stress) have been carried out at different ionic strengths and high pH of the injected water. Proppant particles penetrate deeper into coal matrix at low ionic strength of injected water corresponding to electrostatic particle-particle and particle-coal repulsion. No particle agglomeration and formation of particle-formed cake at the entrance of coal cleats are observed at these conditions. Coal permeability increases by about 2.2 times as the result of a single-sized small particle injection. Followed injection of larger particles leads to a greater enhancement of coal core permeability. An overall increase of coal core permeability after graded proppant injection is about 2.7 times. The proposed method can significantly increase very low productivity index in stress sensitive coals and shales without hydraulic fracturing. It can be also used as a non-damaging leak-off additive during hydraulic fracturing stimulation treatments and to aid long-term conductivity.

The Breagh gas field lies in the UK Southern North Sea, 100 km east of Teesside in Blocks 42/13, 42/12a and 42/8a. The normally-unmanned gas field came on stream in October 2013 and is the first offshore development of the Yoredale formation of the Lower Carboniferous. The reservoir comprises a mixture of sand sheets and channels with permeabilities predominantly in the range 0.1 to 10 md. The plan for the first phase of Breagh Field development was to drill 10 conventionally completed 65° angle deviated wells, through the reservoir, from a 12 slot platform. Analysis of log and PLT data from some of the initial wells identified channel sands, tighter than expected, yet containing significant GIIP. Wells 7 and 8 of the first phase of drilling were completed using hydraulic fracturing to evaluate the potential for improvement in productivity and drainage from the lower permeability intervals, although the execution of the stimulation programme brought significant challenges. This paper introduces the Breagh Field, discusses the reasons behind the change in completion design to include hydraulic fracture stimulation, considers the challenges associated with fracture placement in high angle wells and solutions implemented. The paper also addresses the importance of the clean-up phase, and reviews the lessons learned. In support of this programme, a number of hydraulic fracture designs and modelling methods were evaluated and used to make real time decisions during stimulation operations. These methods are discussed and used to estimate the value of hydraulic fracture stimulation in the Breagh field to date. The first two wells to be stimulated on Breagh have been successful, yielding initial increases in productivity of the order of 4–10 fold. The magnitude of this increase has led to a forecast of significantly higher recovery from the lower permeability sands and from the total field. Important learnings from the subsurface characterisation, fracture planning and execution phases have been made. As a result of the success to date, hydraulic fracture stimulation is being integrated into the well completion planning and facilities design for the next phase of Breagh Field development.

The downside of the conventional perforating method with explosive charges and guns is that it is risky. In addition to this, the method has a negative effect on the near wellbore permeability, and it creates mechanical damage. The impact stress associated with shaped charge and the outward travelling shock wave weakens the rock matrix, which increases the risk of sand production. Another negative impact of the shape charge is the creation of a low permeability zone, in which sand grains are forced toward the vicinity of the perforation chamber. For example, a perforation process with a 55% permeability reduction around the perforation tunnel led to 60% reduction in well productivity. An intended large underbalance differential pressure offers, to some extent, a solution to clean up the crushed zone. However, the de-bonded and weakened structure of the damaged zone is irreversible. The required surge pressure to clean up the perforations varies from 200 to 5,000 psi, because not all the perforations react the same way. On the other hand, built-in nozzles cause no damage to the formation, because no charge or shock is imposed to the formation. Furthermore, there is no longer an impact from underbalance or overbalance pressure differential between wellbore and formation. In this paper, we will introduce the engineering and mechanism of built-in casing (BIC) nozzles. With BIC, nozzles are activated from surface with deployment of specific activation tools. Once the tool engages with the targeted profile, the nozzles are opened and projected to the wellbore fluid. With circulation of cement-dissolving fluid, cement breaks and formation connection is initiated. Quantity and size of nozzles are engineered as per downhole production design criteria. In unconsolidated or poorly consolidated reservoirs, the strength of the rock structure should be evaluated to reduce the risk of sand production. Ultimately, the differential pressure shall be high enough to effectively clean the perforations, but not so high as to cause sand production. As mentioned above, there are a great deal of scenarios and variable parameters involved in perforation with shape charges that have to be taken into consideration to ensure an effectively performing set of perforations. Because such a study and remedial approaches are costly and not always guarantee results, an alternative method is to use BIC perforations.

Candidate recognition in mature brown fields and depleted fields for stimulation has always been a challenging task. It has become a common practice for many operators that when all else fails they turn to stimulating the well. The application of fracturing for any poor producer in a brown field does not guarantee success. Since traditional reservoir engineering methods like skin analysis via build-ups cannot be applied in these depleted reservoirs alternative techniques have to be used. Identifying and stimulating key wells requires a systematic candidate recognition process with emphasis on the ability of the well to deliver post stimulation. Having a method to score completion and production integrity based on its petrophysical and geomechanical characteristics and thoroughly understanding the operating environment ensures a much better chance for these wells to be successful. Comprehensive candidate selection methodology with available data was devised to identify best stimulation candidates from existing set of wells. Comparative Petro-physical log evaluation, Mechanical Earth modelling and oriented perforations in selected wells was deployed to further understand reservoir and rock mechanical properties and limit surface pressures by minimizing near wellbore perforation and tortuosity effects. Further to estimate economic viability; analytical modelling and Arps production decline was combined utilizing local learnings and experience to predict post fracture production. Full set of diagnostic tests was done to make a robust model that can simulate fracture propagation and help in optimizing fracturing design to place desired fracture in place. Post fracturing cleanup and well activation was closely monitored with design and recommendation on required Artificial Lift techniques as and when required. Production results achieved after applying this workflow exceeded initial expectations set by operator. Payout period achieved for total investment in this project was 75-150 days. Due to these encouraging results, same workflow was applied in number of depleted fields in Cambay basin with similar results. This paper will summarize the workflow used for revitalizing production from some of the major fields including Candidate selection methodology, Petro-physical evaluation, Mechanical earth modelling, diagnostic tests for fracturing design, production forecasting, post fracture well activation and artificial lift design. In the end, possibilities of deploying this workflow for re-vitalizing other brownfields will be discussed.

Effective and uniform placement of treatment fluid across multiple zones can be challenging. This is particularly true during stimulation or remedial treatments for formation sand control, as well as during water shutoff treatments. Such challenges can be greatly enhanced when a long interval sand formation is largely heterogeneous. Good diversion technology is often what dictates treatment success. Current laboratory methods used to study diversion at downhole conditions can leave a large gap between laboratory and actual operational results. A recent midscale laboratory study involving a new complex multizone formation testing system has helped provide a method for closely simulating downhole conditions. This paper describes a new laboratory testing setup, which allows an effective dynamic study of diversion. The new testing apparatus allows for evaluation of different critical parameters, such as concentration, temperature, and pressure on the diversion mechanism. Results are presented for laboratory case studies of diversion during different scenarios, including formation sand/fines control treatment and water shutoff treatment. The results generated can provide insight to help bridge the gap between a laboratory study and operations encountering multiple zones.

Historically, leak-off analyses of stimulation fluids have been performed using in-house laboratory procedures. The lack of industry standard procedures to perform leak-off and wall building coefficient analyses of stimulation fluids has introduced inconsistency in both results and reporting for many years. A technical standard adopted in 2006 by both API and ISO for static conditions has provided the oil and gas industry with the first standardized procedure to measure and report leak-off 1 . However, the more complex testing under dynamic conditions was not addressed. As a result, a group of industry experts have compiled their years of experiences in developing a new technical standard to measure the leak-off characteristics of stimulation and gravel-pack fluids under dynamic flow conditions. Stimulation and gravel-pack fluids are defined, for the purpose of this technical standard, as fluids used to enhance production from oil and gas wells by fracturing and fluids used to place filtration media to control formation sand production from oil and gas wells. Leak-off is the amount of fluid lost to porous media during these operations. The leak-off procedure was developed through the collaboration of several industry companies by evaluating numerous in-house laboratory techniques and conducting round robin testing to ensure that any modifications to these procedures were reliable and repeatable. The new standard provides a step-by-step procedure that includes fluid preparation, experimental equipment design, testing procedure and data analyses for fluids exhibiting viscosity controlled leak-off or wall building characteristics. Example calculations are reviewed within this paper.

The Abu Rudies field in the Egyptian Sinai peninsula produces mainly from the South Gharib formation that is characterized as a complex, heterogeneous, thick and laminated, but permeable, slightly oil wet rock and depleted sandstones consisting of sands with an average permeability in the range of 150-550 mD and Young's Modulus in the order of 1.0 - 2.5 million psi. Conventional hydraulic fracturing and Frac & Pack techniques have been traditionally deployed to produce hydrocarbons and for sand control. The added complication is the reduction in the effective permeability to oil due to the rock being oil wet. Conventional fracturing techniques have had limited success especially in the highly permeable compartments of the field due to premature screenouts that were encountered extensively, residual polymer in the intergranular porous rock and the flowback of formation sand and proppant. This paper describes the application and production enhancement efforts for the first time with a novel channel-fracturing technique combined with rod-shaped proppant in selected production targets in the Abu Rudies field in Egypt. The channel fracturing technique introduces channels within the proppant pack that significantly increase conductivity and effective fracture half-length leading to increased productivity. Rod-shaped proppant when used as tail-in in fracturing treatments increases near- wellbore fracture conductivity and completely prevents proppant/formation sands flowback as demonstrated by zero flowback due to its particular geometry. This paper describes actual case studies of fracturing a high-permeability layered reservoir using the channel fracturing technique, the problems encountered due to high leak off, low closure pressures, reservoir heterogeneity and the complexity due to adjacent water bearing layers. Finally, we demonstrate the well performance with the channel fracturing technique compared with alternate techniques.

The stimulation history in offshore Brazil is undergoing into a deep transformation. The requirements of technology, before focused on sandstone reservoirs demand, are being expanded by the need for techniques to stimulate carbonate reservoirs, specially the pre-salt carbonates. In this scenario, a self-diverting acid system based on a viscoelastic surfactant (VES) technology was introduced for carbonate reservoir stimulation. The Self-Diverting VES (SD-VES) promotes viscosity development when the acid comes in contact with the carbonate formation. The mechanism of viscosity development is simple: In concentrated acid, the system presents low viscosity, which results in friction reduction while pumping; however, when the fluid reacts with the formation and the acid concentration decreases, the micelle spherical structures combine, transforming into rod-like micelles that convert to a 3-D structure, which increases the fluid viscosity. The high viscosity generates a temporary barrier across the high-injectivity zones, diverting the subsequent fluid to treat other reservoir zones. Generally the SD-VES is associated with several placement techniques that aid in achieving good treatment distribution through the entire producer interval. Regardless of the placement technique applied, the SD-VES is generally used as the main acid fluid and is bullheaded into the well. Because of its rheological behavior, the SD-VES is pumped as a single fluid during bullheading, aiming to achieve formation stimulation and good treatment distribution throuth the entire productive interval. Since the SD-VES was introduced in 2009 to treat carbonate reservoirs in offshore Brazil, more than 40 wells have been treated using the system in the various acid placement techniques presented in this paper. Three case histories are presented to better illustrate the different scenarios where the SD-VES was applied.

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.

Brine workover fluid has a confirmed damage for gas condensate wells generated by both water blockage and fines presented in it. Studied reservoir is a gas condensate field where workover operations performed for replacing downhole equipment have induced severe damage. Formation damage for brine workover fluid was tested on core for both hydrocarbon flowing phases (condensate and gas) and revealed up to four times decreasing in permeability. Laboratory research was then oriented to identify the best solution to remove induced damage. It was tried to identify how much of damage was induced by water blockage and how much by fines present in workover fluid. Tests revealed a good recovery of permeability for gas by using alcohol/surfactant fluids but not close to original permeability. On the other hand correctly formulated mud acid solution have removed induced damage and increased the permeability up to three times more than original permeability. Results have been implemented on field Burcioaia and foam acidizing was used successfully in field tests. For very long perforated intervals foam was used as diverter. In some cases only acid solution was foamed and in other cases also neutral foam was pumped in slugs in between acid stages. Case histories for performed removing damage jobs are also presented.

Well planning in mature fields can be challenging as the more marginal reserves are targeted. Hydraulic fracture stimulation is a key technology to access multiple reservoir layers and thereby maximize recovery. However, fracture propagation in low porosity carbonates may be strongly confined because of high tensile strengths in bounding layers. The strong confinement can impede vertical fracture propagation and the ability to access reservoir units adjacent to the initiation interval. Understanding vertical hydraulic fracture growth through low porosity layers improves the hydraulic fracture design, enhances reservoir deliverability potential and enables the identification of infill well potential and intervention opportunities. The South Arne field is located in the northern part of the Danish sector of the North Sea. The Tor and Ekofisk formations are high porosity/low permeability chalks with low to moderate natural fracturing. Porosities may reach 45%, but a hard low porosity interval of 10% or less at the bottom of the Ekofisk formation separates and partially compartmentalizes (horizontally) the two formations. A series of indirect tensile strength measurements on South Arne cores were conducted. The measurements verified a suspected exponential increase in tensile strength at low porosities, essentially causing the tensile strength to exceed 1,500 psi in some cases. Recent 4D seismic surveys have enabled separate sweep patterns for each reservoir unit to be mapped and indicate that the sweep is much less efficient in the Ekofisk. This supports that the hydraulic fracture stimulation treatments initiated in the Tor formation are not accessing the upper units to the degree previously assumed and it appears that connection is occurring via pre-existing faults and/or natural fractures. The hydraulic fractures propagate nearly longitudinal to the wellbore, guided by regional stresses, with limited height growth. However, production effects, specifically compaction induced by draw down, may perturb the stress field sufficiently so that the preferred alignment is not achieved, further reducing sweep efficiency. This is indicated by 3D coupled geomechanical modeling and is corroborated by 4D seismic observations.

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.

Total operate a field located 150 kilometers off the Niger Delta at a water depth of 1,400 meters. This field is the first deep-offshore development involving light oil with high gas content. In the field's Miocene reservoir the fluid is under saturated (~ 80 bar) and in ‘critical conditions’, i.e. the gas and liquid hydrocarbons are in a single phase, at high pressure and temperature. Several turbiditic-type reservoir layers are developed with 22 oil producer wells, 20 water injector wells and 2 gas injector wells. Reservoir G is a lobe sand body with good petro-physical characteristics (Permeability = 300 to 500 mD, Porosity ~ 20%). This reservoir is developed with 2 producer wells, well 7 and well 9, completed with frac-packs, and 2 water injector wells for pressure maintenance. In September 2009, six months after first oil, well 7 and well 9 lost 70% of their potential following the decline of their productivity index. The impact was 20,000 bpd production shortfall. This paper describes the investigation process that was conducted to identify the cause of the decline. The process included pressure transient analysis, geochemical analysis, core flooding tests and scale modeling. A trial and error approach was adopted when designing well intervention in order to get as much information as possible and firm up the most realistic cause of production damage. This paper also highlights the fact that a proper diagnostic requires a multi-discipline approach, an open mind and a comprehensive risk analysis.

The oilfield Tchendo, located 18 miles off the coast of the Republic of Congo, has been operated since 1991 by Total E&P Congo in depths of approximately 100 meters of water. The shallowest of the three reservoirs, the Sénonien reservoir (400 m TVD SS), involves an intercalation of carbonate layers with thicker (5 to 15 meters) but poorer quality siltstones. Various attempts to enhance productivity on existing wells were unsuccessfully carried out since initial production, including selective or extensive perforation, acid treatments on the carbonate layers, and, in recent years, hydrajetting fracture stimulation on three wells. Although the field is non-conventional, so far, it has been developed conventionally. A large amount of the original oil in place still remains in the reservoir. To make the redevelopment project viable, a step change in stimulation techniques is to be undertaken. Two workovers were performed at the end of 2012 as a "proof-of-concept". Innovative fracturing technologies, including hydrajetting, were combined to deliver a non-sleeve scenario for horizontal well multi-stage fracturing. The workovers resulted in the largest fracturing treatment executed by Total on an offshore well. This paper reports on the lessons learned in the process of fracturing this non-conventional reservoirs that will be capitalized for the future redevelopment of the project.

Carbonate scaling is one of the common problems that occur in wells producing high amount of water. The tendency of scaling escalates in mature fields. This problem becomes critical in sub-hydrostatic wells with Electrical Submersible Pumps (ESP). In such cases, the scale not only reduces the flow of fluids into the wellbore, but also causes frequent failures in downhole equipment, eventually stopping production leading to well workover. Frequent ESP failures can increase the operating costs to unacceptable levels which may eventually lead to field abandonment. Joint Operations (Chevron and KGOC) in Partitioned Zone (PZ) faced severe scaling problems in Humma field producing from Marrat Carbonate reservoir. A thick layer of calcium carbonate scale was observed in the completion string during the workover. As a result of this scale, ESP repair and replacement frequencies increased abnormally. Also, the ESP amperage charts showed erratic behavior due to solids interference inside the pump resulting in pump failures. A combined scale control and stimulation treatment was applied in three wells in Humma field in Joint Operations to slow down scaling tendency in the formation and tubular. These wells are producing up to 1523 BWPD averaging 28% water cut. The treatment provided effective placement of scale inhibitor in the formation while controlling any increase in water production because of stimulation. As a result, the workover frequency due to pump failures was reduced. Not only did the production improve, the amount of deferred oil was also significantly reduced resulting in direct oil gain and significant savings in operating costs. This paper describes the lab analyses, treatment design and execution procedure, adopted for the implementation of this technique as well as the recommendations and lessons learned from the field experience.

The CaraCara field in the Los Llanos area of Colombia is a highly permeable (1 − 3 Darcy) sandstone with more than 10% total clay content, producing heavy crude. Gravel packing is required to avoid sand production. However, the Productivity Index after conventional gravel packing is only 50% of the open-hole potential due to drill-solids—calcium carbonate —plugging the matrix and fines migration. Non-acid and acid based preflushes have been used to dissolve the drill-solids and fines in the critical near wellbore matrix respectively. However, corrosion, uncontrolled filter cake dissolution, sludging with heavy crude and disposal of spent acid limits the use of acid pre-flushes. A recently developed non-acid based fluid capable of stimulating high temperature sandstone formations was taken as the starting point to develop a customized solution to remove formation damage and control fines migration for this particular application. The base fluid is chelant such as diammonium EDTA (DAE) to which a low concentration of HF acid is added, most commonly in the form of ammonium bifluoride. The HF acid greatly increases the dissolution of aluminosilicates, while the chelant prevents the precipitation of silica gel. The addition of boric acid effectively retard the dissolution rate of the fluid as boric acid the reacts with the HF acid to form fluoroboric acid (HBF 4 ) which slowly hydrolyses to release HF acid. Fluroboric acid also provides an effective means of fines migration control. By adjusting the concentration of acid salts in the fluid as a function of temperature the fluid can provide effective controlled filter cake removal, matrix stimulation and fines migration control, at temperatures between 120 and 300°F. The newly developed non-acid fluid system provides some unique advantages for gravel packing and matrix stimulation applications in highly permeable heavy oil reservoirs 1) A single carrier fluid, eliminating the need for preflushes 2) Controlled filter cake dissolution ensuring circulation is maintained while gravel packing horizontal wells. 3) Effective fines migration control. 4) Scale inhibition. 5) Crude compatibility and negligible corrosion rates. In one field the average productivity index of vertical wells completed using this fluid increased from 0.2 bbl/psi to 0.9 bbl/psi. The final skin values were close to zero and the production remained stable for an extended period of time. A similar fluid when used in horizontal well applications reduced the cleanup time from days to hours. The ability to stimulate while gravel packing optimizes the productivity of dirty sandstones while minimizing the cost.

An operator in Ecuador produces from the Napo "U" sandstone formation with permeability ranging from 90 to 2,000 mD. A lateral aquifer supports the oil production coming from this zone. Water breakthrough in this formation is common in intervals with high permeability streaks causing the water cut to increase substantially, thus affecting the oil producing zones. Besides the onset of water, additional oil decline results from high pressure drawdown and high clay content (including kaolinite) in the formation. The primary damage mechanism is identified as fines migration, a common problem in wells in Ecuador. The main challenge is to increase oil production through stimulation in wells with high water cut and a strong aquifer, without increasing the water cut. A treatment was proposed that would remove the damage in the intervals producing oil and "good" water without stimulating the interval where water had already broken through. It consisted of combining a modified organic clay acid (OCA) and a viscous disproportionate permeability modifier (VDPM) to maximize zonal coverage and minimize water production. The first stimulation treatment using the modified OCA and the VDPM enabled the treatment to be diverted to the intervals where water had not broken through. Post-treatment results showed production had doubled and water cut remained the same as it was pre-treatment. Production then remained stable after more than 3 months. A nodal analysis model predicted that the well had a skin of approximately 10 prior to the treatment, and this skin was reduced to nearly zero following the treatment. A subsequent stimulation treatment performed in a horizontal openhole completion using coiled tubing increased oil production by more than ten times the initial production. It was not known where in the openhole the water breakthrough had occurred in this well, but through the use of the VDPM, the water cut was reduced. An additional 13 wells with similar damage have been treated successfully using the same fluids resulting in an additional 2,100 BOPD of production. The combination of effective diversion, conformance control and modified OCA is an effective means of selectively increasing oil production in mature fields without increasing the water cut.

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.