Kazakhstan owns one of the largest global oil reserves (~3%). This paper aims at investigating the challenges and potentials for production from weakly-consolidated and unconsolidated oil sandstone reserves in Kazakhstan. We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves, in Kazakhstan, were studied in terms of the depth, pay-zone thickness, viscosity, particle size distribution, clay content, porosity, permeability, gas cap, bottom water, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, geological condition, including the existing structures, layers and formations were addressed for different reserves. Weakly consolidated heavy oil reserves in shallow depths (less than 500 m) with oil viscosity around 500 cP and thin pay zones (less than 10 m) have been successfully produced using cold methods, however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical in comparison to the similar cases in North America. The complicated tectonic history, necessitates the geomechanical models to strategize the sand control especially in cased and perforated completion. These models are usually avoided in North America due to the less problematic conditions. Further investigation has shown that Inflow Control Devices (ICDs) could be utilized to limit the water breakthrough, as water coning is a common problem, which initiates and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavy oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.

Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters to evaluate the quality of various operations during the life of a well. The evolution of formation damage over the long run is rarely studied. This paper will present a new model of time dependent skin factor measurement. Multiple field examples are analyzed and modelled comparatively to evaluate the magnitude of the time-lapse formation damage for specific reservoir rocks. Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and individually compute the contributing mechanisms of actual damage. Formation damage is a combined effect of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well clean up, organic substance deposition, multiphase flow effects, etc. The proposed innovative approach utilizes the skin factor in pressure transient analysis to measure the time-lapse evolution of formation damage. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type. This paper will present an innovative technique and methodology to quantify the formation damage that has been materialized during the life of a well, from drilling to production. A robust technique to quantify the total damage is the computation of the skin factor from pressure transient tests conducted at various times. Observations confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time. Pressure transient tests conducted after drilling, casing, and perforating were analyzed. These initial pressure transient test results were compared with production tests performed years after drilling. Various field examples from North African reservoir rocks are presented to depict the applicability of the time-lapse method to quantify the formation damage for a given specific reservoir rock. Remedial stimulation work has been performed in such damaged wells. Formation damage could be removed, and the productivity has been revamped. The stimulation procedure has been based on core plug tests of various stimulation fluids. Potential stimulation strategies to remove or minimize formation damage are also discussed in this paper. In this paper a new methodology and mathematical relation have been described to quantify the time-lapse formation damage mechanisms. Field examples from North African reservoirs have been depicted. The findings could be easily utilized to apply the time-lapse methodology for similar reservoir rocks in other parts of the globe to measure and quantify the magnitude of the formation damage.

Petroleum wells producing water are likely to develop deposits of inorganic scales that may form near the wellbore and may plug perforations, coat casing, production tubulars, valves, deteriorate pump performance, and affect downhole completion equipment. Scales form and precipitate because the solution equilibrium of water is disturbed by pressure and temperature changes, dissolved gases or incompatibility between mixing waters. If scale formation and precipitation are allowed to proceed, scaling will limit production, eventually requiring abandonment of the well. In order to remove the effects of scale on production after a well undergoes sharp or early decline in production, it is essential to first determine which scales are forming and where they are forming. Some of this information can be reliably inferred from computer simulation procedures or by running calipers down the wellbore and measure decreases in the tubing inner diameter so that the scale can be physically detected. Gamma ray log interpretation may also be used to detect barium sulfate scale because naturally radioactive radium precipitates as an insoluble sulfate with this scale. Scale remediation techniques must be quick and nondamaging to the wellbore, tubing, and the reservoir. If the scale is in the wellbore, it can be removed mechanically or dissolved chemically. Selecting the best scale-removal technique for a particular well depends on knowing the type and quantity of scale, its physical composition, and its texture. Mechanical methods such as Dynamic Underbalance Pressure (DUP) technique are among the promising methods of scale removal in tubulars and across perforations. The purpose of this work is to present a case study of removing barium sulfate (BaSO 4 ) scales from perforation tunnels utilizing dynamic underbalance technique. Wells from a North African oil field were selected for designed and optimized dynamic underbalance treatments to remove barium sulfate scales that precipitated in the perforation tunnels, preventing hydrocarbons flow from the formation to the production tubing. Gamma ray log and production logging tool were used before the treatment to detect and evaluate the type of scale and the intervals affected. Then the same tools were used after the treatment to assess stimulation taking place in the wells. Data obtained from the treatment was used to develop a model for predicting productivity index/inflow performance relationships. The dynamic underbalance technique successfully removed scale from all targeted wells, leading to an increase in oil production, without killing them (i.e. while still in production). Some wells achieved increase in oil production after the treatment of up to 65%. A predictive model was developed in order to estimate the performance of an underbalance scale removal treatment.

The development of well completion strategy at the subject field has evolved from simple vertical completions to extended horizontal wells with selective openhole completions (Etuhoko et al. 2014). Normally, well completions in this field involve large volume acidizing treatments. Matrix acidizing and acid fracturing stimulation are widely used in carbonate formations to improve oil recovery arising from the high solubility of the carbonate formation in hydrochloric acid. The ability to create wormholes in the near-wellbore vicinity provides a stimulation effect by connecting to secondary porosity (natural fractures, voids, and vugs). The connection of the natural fracture network to the wellbore utilizing acid fracturing treatments provides a stimulation effect because the hydraulically fractured reservoir increases the effective wellbore radius and results in a negative skin factor. However, massive acid treatments raised certain issues after beginning to develop oil-bearing zones near water/oil contacts. Significant water production occurred in some flank wells after acid stimulation. High permeability channeling is suspected between the aquifer and the wellbore. There is a high probability of water flow through natural fracture networks because no barrier exists to prevent drainage from the aquifer, which is connected to the wellbore with acid-stimulated wormholes or via acid etched fracture faces. Because production facilities are not designed to handle a high water volume, production wells with an unfortunate water cut are shut down. Obviously, field economics suffer and an effective water shutoff solution is now a vital component of future field development. Although many advances have been made in both mechanical and chemical methods to reduce unwanted water production, horizontal wellbores present challenges. If water breakthough is recorded, the field operator conducts a multiphase production log (MPLT) survey to identify the influx depth. The first choice for water shutoff is usually a mechanical isolation in which the water-producing interval is either shut in by a sliding sleeve (SS) or the entire wellbore is isolated by bridge plugs. Unfortunately, mechanical isolation does not help because the water flow easily bypasses the restriction by flowing through the carbonate formation and enters the wellbore in the upper interval ( Fig. 1 ). The most recent approach includes a total shutoff of the water-producing interval by placing a polymer sealant in the targeted zone. Several chemical water shutoff jobs have already been performed by the field operator. Although some of treatments can be considered successful as a result of proven reduced water cut over an extended time period, some treatments did not provide the expected results, despite a large chemical volume pumped into the formation. Figure 1 Schematic of horizontal well before the chemical water shutoff treatment. This document describes the materials used for chemical water shutoff purposes and the history of the technology application in the subject field. Avoiding known pitfalls and following best operational practices may help to increase the success rate of chemical water shutoff treatments.

As part of an Equinor technical efficiency programme that was initiated in 2015 to deliver savings and improvements, bridging particles were removed from the drilling fluids of 15 wells on Oseberg Main and instead loss control material (LCM) was used, as required, in some but not all the wells. These long, horizontal wells were a combination of open hole (OH) and sand screens with and without inflow control together with cased & perforated (C&P) completions, producing from typical Brent Group sandstone formations with permeabilities varying from approximately 10 mD to Darcy sands, and which were depleted by as much as approximately 280 bars. In 2018, an extensive study was performed on these wells to determine the impact on inflow performance of drilling without bridging particles. It was realized that the 15 wells offered a worst-case scenario to study in the field rather than laboratory the significance of formation damage on well productivity. The data set generated offered a unique opportunity to challenge conventional formation damage assertions, especially for long, horizontal wells, examples of which are as follows. Formation damage reduces productivity Significant mud losses with deep penetration lead to wells with lower than expected inflow performance Bridging particles are required to prevent formation damage around the near wellbore Drilling through heavily depleted reservoirs will result in severe formation damage Excessive use of graphite in an OH reservoir section will reduce inflow performance The influence of different parameters, including loss control materials, lower completion design, loss type, mud penetration depth, dynamic overbalance while drilling, length of production interval, net to gross (NTG) and kh were considered for those wells drilled without bridging particles. One of the surprising findings was that there was no clear evidence that losses were detrimental to the productivity of these long horizontal wells, i.e. it would appear that the Brent reservoir sections, despite being depleted, were more resistant to the influence of formation damage on inflow performance than first thought. Furthermore, for this example bridging particles appear to be of less importance in the avoidance of formation damage but are important in preventing excessive increases in fluid costs due to losses. After a thorough review of all the data obtained from this study, together with the conclusions drawn, it was realized that these had direct implications for Equinor's approach to fluid qualification, and especially coreflooding. The most important conclusion that influenced this change in approach was that the long reservoir sections (approximately 1 km or more) within typical Brent heterogeneous formations appear to tolerate more formation damage without impairing the productivity index (PI). A direct consequence of this was the conclusion that more emphasis should be placed on fluid compatibility, mobility, screen plugging and stability along with particle size distribution (PSD) design while the importance of coreflooding to fluid qualification was downgraded for Brent and reservoirs of similar chacteristics. This is not to say that coreflooding will not be performed, but rather it will be targeted towards situations where the influence of formation damage on well productivity is more significant, e.g. HTHP fields where special drilling and completion fluids are required, low permeable formations without mechanical stimulation, and shallow reservoirs with low reservoir temperature. This paper will perform an evaluation of the significance of formation damage on well productivity and use this to demonstrate Equinor's revised approach to formation damage laboratory evaluation based upon field experiences.

A new perforating technique employing the integration of conventional shaped charges and solid propellant was described by Albert, et.al. (SPE 197185-MS). The innovative propellant deployment method allows the propellant deflagration to occur in the perforation tunnel rather than gun body and casing, thus delivering maximum energy to improve perforation tunnel performance. Shaped charges utilizing high energy explosives perforate casing and formation with high speed metallic jets that displace by sheer force. The explosive events are fast (20-30 microseconds) high impact events (as high as 1.5 million psi at the rock face) that can collapse large pores in the formation along the surface of the perforation tunnel. This crushing along the tunnel reduces permeability and increases skin and can impact the flow of fluids into and out of the reservoir rock. A number of methods have been developed to improve perforation tunnel flow efficiency, but all suffered limits on either deployment or effectiveness. Propellants have been used for decades to improve perforation performance. Propellants are energetic materials with slower burn rates that can micro-fracture the formation and break-up the crushed zone around perforation tunnels. Prior methods deflagrated the propellant materials within the gun bodies, or casing and lost a significant amount of energy before delivering impact to the perforation tunnel. The new method with a composite cap of solid propellant on the face of the shaped charge, displaces the propellant into the perforation tunnel before deflagration, thus delivering maximum energy to the formation. This helps break up the crushed zone and micro-fracture the formation. The improved perforation tunnel will reduce frac fluid tortuosity. Frac jobs can get better fracture initiation and better proppant placement, resulting in better production. This paper will focus on additional lab testing at an Advanced Perforating Flow Laboratory plus several USA onshore completions (horizontal and vertical). The field data will show the effect of the composite perforation method on frac performance and well production.

A major operator in the Gulf of Mexico (GOM) desired to increase oil production to meet growing energy demand. To meet this challenge, the operator explored an alternate completion design to mitigate reservoir damage observed in previous producing wells and collaborated with the fluids provider to design a solution to address this concern. The design and solution ultimately applied resulted in "negative skin" with production rates far exceeding historical field rates. Additionally, the operator realized significant cost savings with this change in completion approach by eliminating traditional steps. The development field had its unique challenges with ongoing depletion, wellbore instability risks, and compartmentalization in the reservoir, making access to thinner oil reservoirs challenging to develop. The standard completion approach was to drill with a synthetic-based fluid, perforate the casing, and perform a frac-pack completion. Using technology from another region, the operator elected to change the traditional cased hole frac-pack approach to drilling horizontally through the reservoir, run production screens, and perform an open hole gravel pack completion. In the fluids design phase, the fluids provider performed hydraulics modeling and laboratory testing on multiple formulations, including brine compatibility with formation water; formation response testing; high-pressure/high-temperature (HPHT) rheology and fluid loss; static age testing for intervals of 16 hours, 3 days, and 5 days; and contamination testing with solids, synthetic-based mud, and cement. This paper discusses the methodology used in the design phase required to engineer a reservoir friendly fluid to meet the challenges faced with this complex well.

This paper describes field experience of designing a successful scale squeeze program for an oil well. This was done utilizing an adsorption isotherm derived from a core flood data from other reservoir. Correlation and reliability of the adsorption isotherm with actual field flow back data after squeeze treatment for a period of 18-month are given. Moreover, utilizing the knowledge generated, a bespoke multilayer adsorption isotherm was optimized for a treated well for more efficient squeeze design for next treatment. In order to achieve our objective, an adsorption isotherm from other reservoir core flood was first generated. With the knowledge not limited to current candidate well production rates, well properties, perforation height, number of zones and other essential parameters, a 18-month squeeze treatment program was designed. Water chemistry 18-month data was utilized to validate the scale squeeze design. An improved multilayer adsorption isotherm bespoke for this well was generated. In conjunction with flow-back production data, a scheduled sampling program and water analysis utilizing Inductively Coupled Plasma (ICP) for post treatment Scale Inhibitor (SI) residuals data was collected to validate the adsorption isotherm derived from other reservoir. As predicted by the model for post treatment monitoring, the SI residual concentration; back calculated from SI chemistry utilized for the treatment are found to have an excellent correlation with the adsorption isotherm derived from a different reservoir. Hence, the 18-month squeeze design derived from a different reservoir was a great success. The slight difference between real flow back data and the adsorption isotherm generated from other reservoir become a benchmark to derive an improved adsorption isotherm to optimize the scale inhibition protection than the current treatment. In summary, parameters such as mineralogy study, porosity, permeability, crude properties and dynamic scale loop (DSL) study are the utmost important information to be analyzed prior using other reservoir core flood data as reference. As results shown, these are the best way to generate squeeze design with limited information had in hand.

Objective/Scope The objective of this paper is to present a successful acid frac technique applied in a deep HPHT well to enhance the productivity of Marrat reservoir. Method, Procedures, Process Jurassic reservoirs in the state of Kuwait are deep, sour and tight with High-Pressure and High-Temperature (HPHT) environment. Challenging reservoir quality like low permeability, low porosity, uncertainty about some natural and induced fractures, high stress, etc limits the productivity development for this reservoir. The subject well was drilled up to 16,790 ft with high-density Oil Base Mud (OBM), upto 17 ppg, targeting Marrat formation to prove hydrocarbon in this area. Formation damage caused due to invasion of high-density mud, using Barite as a weighting agent, into the carbonate reservoir poses a challenge to design a proper stimulation treatment to restore the permeability and to evaluate the real reservoir potential. Since the damage caused by OBM invasion cannot be easily treated, it was decided to stimulate this reservoir either by matrix or fracture stimulation. The subject well was tested with Drill Stem Test (DST) and perforated in underbalance condition using TCP gun. Acid treatment was performed with 28% emulsified acid solutions to gain the deep wormhole penetration in order to enhance the well productivity. Pre and Post stimulation flow measurement confirmed a slight improvement in productivity. But still there is a scope for increasing productivity further more. Based on the test results, it was decided to Hydraulic Frac the Jurassic reservoir to achieve the expected potential. A detailed study was carried out to identify reservoir quality and completion challenges that limit the development of reservoir potential and to recommend remedial mechanism, acid or proppant frac, to improve the well productivity. Based on the analysis, acid frac design and procedure was established to gather data and improve productivity from Marrat reservoir. Prior to the main fracturing treatment, a data-frac was conducted to determine reservoir parameters such as fracture extension pressure, fracture closure pressure and instantaneous shut-in pressure. Based on data-frac results, acid frac was successfully executed and the well productivity was tremendously improved. Results, Observations, Conclusions High injection surface pressure of 13,800 psi and high leak-off was observed during main acid treatment due to the tight nature of the formation that resulted in low fluid efficiency and relatively short etched fracture length. Acid fracturing treatment was carried out successfully without encountering any major operational issues. The post-acid frac production results show significant improvement in productivity Index(PI) and 3-4 folds increase in production comparing to main acid treatment results. Post-frac analysis was carried out on the sustained production from the Jurassic reservoir. Novel/Additive Information Improvement in well productivity after the acid frac stimulation confirmed the well potential and supported exploration group to achieve the reserve target.

In onshore Middle East, local practices for matrix stimulation of openhole horizontal carbonate water injectors consist of spotting hydrochloric acid treatment via coiled tubing (CT) along the uncased section using a specific fluid dosage per unit length of the pay zone. Thus far, that approach has delivered inconsistent results in wells completed across tight carbonate rock, most often leading to a rapid decline in injection rates following the treatment. An alternative workflow was implemented to take full advantage of real-time downhole measurements and the presence of fiber optics in the CT for telemetry. The approach leverages distributed temperature sensing (DTS) to evaluate the original water injection coverage across the reservoir. Results enable segmenting the open hole into intervals requiring different levels of stimulation. Each section benefits from a customized treatment that increases injectivity and improves uniformity of injection. A high-pressure jetting tool, controlled with the help of real-time downhole pressure data, is key to that workflow because it enhances penetration of acid into the targeted intervals. Previous studies showed that energized acid is key to a successful stimulation of tight carbonates. However, the use of CT to convey and pump acid along the open hole often limits the rate at which fluid is pumped, and customized nozzles may fall short of expectations if the downhole conditions are not favorable to their proper actuation. The introduction of real-time downhole readings and DTS surveying into the stimulation workflow helped overcome those limitations and get the most out of equipment and fluids. DTS offers a visualization of high- and low-intake zones along the open hole throughout the operation, thus enabling informed decisions on design adjustments for each stimulation stage. Downhole pressure measurement is instrumental in determining whether downhole conditions are favorable for the use of the high-pressure jetting nozzle, which has a direct impact on the exact pumping sequence, with the potential addition of stimulation stages to bring the openhole in optimum conditions. Downhole pressure reading also allows optimal operation of the jetting nozzles within the designed range. The engineered workflow has been successfully implemented delivering injectivity improvements of nearly 8,000 B/D in the intervened wells, with the DTS survey confirming significant gains on injection coverage along the openhole section. This advanced matrix stimulation workflow, brings reliability and flexibility to the acidizing of tight carbonate water injectors. Use of the full array of downhole parameters not only yields unprecedented injection coverage in complex reservoirs, it also eliminates uncertainties associated with wellbore conditions and helps in keeping injection under the fracturing gradient, thus eliminating the risk of differential sticking events.

Objectives/Scope: The paper is a case study of the impact of acidizing in a carbonate formation. The paper shares the operator’s observations and the approach taken to investigate the matter. The operator’s success in improving the acidizing approach is also discussed in detail. The paper also briefly touches on the effect of acidizing towards water flooding management and steps taken to manage the risk. Methods, Procedures, Process: The study involves investigating behind casing communication post acidizing of a large middle east heterogeneous carbonate field where water injection is expected to commence soon. The field of interest has a reservoir thickness of 90-100m with vertical variation of permeability (10 md to 150 md). To achieve effective acidizing treatment and to provide flexibility during water injection operation, the wells were completed as single selective producers. The high permeability zones were isolated using packers with 8 meters separation. All wells completed were stimulated to create wormholes that can bypass the damage area and generate conductive flow paths, thus improving the well productivity. To improve production in the low permeability zones, a higher acid concentration was applied. During production test, it was found that the production rates and well parameters were the same when the zones tested commingled and individually. This triggered further investigation on the impact of matrix acidizing on the reservoir of interest. As part of the investigation multiple surveys were run to determine the acid profile as well as the zonal contributions post stimulation. In addition, simulation study and core flood test were conducted to investigate the acid reactivity and wormhole effect. Results, Observations, Conclusions: Post evaluation it was concluded that matrix acidizing has potentially led to communication behind casing as a result of acid etching through the formation creating channels between the high permeability zone and low permeability zone. It is believed that the higher acid concentration which was used in the upper zone has reacted with the formation and created wormholes around the wellbore with gravity effect having exacerbated the situation further. To rectify the issue for upcoming wells the operator has relooked at the acidizing methodology and has successfully improve the acidizing recipe. However, the communication behind casing for existing wells still remains and this poses a high risk to water flooding management. The operator has taken the opportunity to relook at the water injection management scheme and accordingly made necessary changes to address the issue. Novel/Additive Information: As part of the investigation, distributed temperature survey with fibre optic enabled coiled tubing was run. The technology was able to provide a continuous temperature profile along the well. Since the fibre optic was placed in the coil tubing, the temperature changes were able to be monitored both while pumping and during shut-in. The running of such a tool was new within the region with the operator being one of the first to employ the tool.

Efficient reservoir sweep is critical for operators to boost oil production in the Middle East. This task becomes particularly challenging in carbonate formations, which typically feature permeability ranging from microscopic pores to large cavernous vugs. Extreme heterogeneity disserves water injectors, leading to nonuniform injection profiles. Consequently, water sweeping is inefficient and leaves significant residual oil behind. In the Mesopotamian Basin, the matrix stimulation approach was rethought to address high permeability contrasts and produce the bypassed oil. The methodology relied on coiled tubing (CT) equipped with fiber optics and real-time downhole measurements, a CT-deployed inflatable packer, and a high-pressure rotary jetting tool. The array of downhole readings was leveraged to ensure optimal use of the bottomhole assembly. The high-pressure rotary jetting tool was used in the first run to condition the wellbore tubulars across the inflatable packer planned anchoring depth. In the second run, the inflatable packer was set at the target depth, and the stimulation treatment was selectively pumped either above or below the packer, depending on the depth of the interval of interest. The proposed stimulation technique was implemented in more than 40 wells, which included vertical and deviated water injectors, completed with 3 1/2-in. or 4 1/2-in. tubing and up to 7-in. casing, with two to five perforated intervals averaging 30 to 50 m in total, temperatures ranging from 90 to 140°F, and an average meadured depth of 2500 m. The CT-deployed inflatable packer had an expansion ratio of up to 3 to 1. CT real-time downhole measurements, such as CT internal pressure, CT annulus pressure, temperature, downhole axial forces, gamma ray, and casing collar locator (CCL), were instrumental to eliminate the uncertainties associated with changing downhole conditions and depth correlation. They also enabled a controlled actuation of the downhole tools in subhydrostatic wells, as the pressure imbalance caused by the low bottomhole pressure can generate loss of fluid flow and pressure across the tools. For the first time, the operator was able to stimulate the tight rock in water injector wells, enhancing injection sweeping efficiency and boosting oil production from offset wells. As a result of this campaign, production gains are estimated at 60,000 BOPD, and injectivity increased in average 2 times per intervention. This approach has now become the state of the practice for the operator to stimulate wells with high permeability contrast. This enhanced matrix stimulation technique, leveraged by CT and real-time downhole measurements, brings a new level of confidence to accurately and effectively deploy inflatable packers in wells with challenging expansion ratio and low reservoir pressure. In addition, the proposed technique enables stimulating tight rock across intervals with extreme heterogeneity, resulting in a more efficient sweep and an increase in oil production.

Well re-entry necessary to wash/cleanup suspected barites and barium sulfate residues in two wells located onshore Niger Delta, Wells AA & BB drilled and completed to develop a cumulative of over 700 Bscf of gas and 30MMstb of associated condensate reserves at an initial cumulative potential of 240 MMscf/d, producing below par at about 15% planned daily production. The sand face for these Single String Gas Producers were drilled with 13.8ppg POBM. Post well completion, hookup and initial cleanup, the wells were suspected to have remained suspended with drilling and completion debris also, various HUD's were encountered within completion string. Previous reentries proved rather unsuccessful for the operator as these wells could not be cleaned up even after using 3 different traditional stimulation fluids pumped in high volumes. As a result of the challenges experienced during the previous interventions, the operator sought a different approach which included the deployment of a specialized stimulation treatment, which is a mixture of organic acids, solvents and clay inhibitors with built in corrosion sequestration and de-emulsifiers via CT. This specialized two-fluid treatment comprising of pre-flush and main treatment was sequentially pumped and allowed to soak for 5hrs and 36hrs respectively. CT run planned to be performed with a jetting tool run across the SAS was not feasible as there was no access to the bottom of the SAS assembly as several attempts to mill out the HUD encountered in the tubing string proved abortive. This paper aims at presenting advances in barite dissolving capability with non-damaging stimulation fluid and powerful "descaler" which although reacts quicker in warm environments (>100°F), is not largely temperature dependent to reach depletion with normal reactions taking place within 24hours. The post stimulation results and recovered debris validates the dissolving capabilities for cleaning sulphates of barium, strontium and calcium as well as calcite in wellbores.

Previous studies showed that different parameters influence the plugging of completion tools. These parameters include (i) rock mineralogy, (ii) reservoir fluids properties, and (iii) type of completion tools. Although different methods have been used for unplugging these tools, there is still debate regarding performance of these methods on damage removal. In this study, we assessed the performance of high-power shockwaves generated from an electro-hydraulic stimulation (EHS) tool on cleaning completion tools plugged during oil production. These devices were extracted from different wells in Canada, Europe, and the US. First, we evaluated the extent of cleaning for the plugged completion tools using an EHS tool at the lab-scale. We examined the slots/screens before and after the treatment to show the performance of the EHS tool. Next, we analyzed the mineral composition and morphology of the plugging materials removed after the treatment by conducting X-Ray Diffraction (XRD), Scanning Electron Microscopy (SEM), and Energy Dispersive X-Ray Spectroscopy (EDS) analyses. Finally, we reviewed the pulsing stimulation treatment results applied to several field case studies. The results of unplugging sand control devices at the lab-scale showed that more than 50% of plugged slots/screens were cleaned after 45 pulses of shockwaves. The characterization results showed that the main plugging materials are calcite, silicate, and iron-based components (corrosion products). The results of field case studies showed an improved oil production rate after the pulsing stimulation treatment. This paper provides a better understanding of the performance of shockwaves on damage removal from plugged completion tools. The results could provide a complementary tool for production engineers to select a proper method for treating the plugged tools.

Radial Jet Drilling (RJD) is an unconventional drilling technique using the jet energy of high velocity fluids to drill laterals into the reservoir formation as an alternative to the traditional stimulation technique. In this subject case study, the productivity index in a Middle Eastern well had dramatically declined due to the excessive observed bottomhole pressures. In order to improve the production conditions, a workover operation was recommended using the state-of-the-art RJD technique. The paper explains the stepwise job procedure in the drilling well plan and operations. The production conditions were compared prior to and following the RJD. Finally, the reasons for the limited success of the operation and the lessons learned for guarantying future jobs success are provided. For the RJD perforation in the well, two assembly runs were required: 1) running the RJD assembly consisting of 5/8-in drill bit, the mud motor and the coiled tubing pipe through the drill pipe, in order to open the window in the casing, and 2) running the jet nozzle assembly (no rotation) below the coiled tubing pipe in order to drill into the formation and extend the laterals to the projected lateral depth. Following the review of these procedures and operations, the paper makes a comparison between the plan and the real experience and provides the reasons for the discrepancies. The number of 14 lateral holes (six holes of 131 ft(40 m) lateral depth and eight holes of 65 ft(20 m) lateral depth) with the aperture size of 0.25 inch, were planned to be drilled by RJD. In practice, the number of only eight laterals of different length ranging 34–65 ft(9–20 m), were drilled due to improper design and operational challenges. Comparing the production conditions following the workover with the previous production conditions, a productivity enhancement of 50% was observed with RJD drilling. However, the operation had several drawbacks: the number of the drilled laterals was less than planned, their penetrated length of the laterals was lower than the planned, and the duration of the well drilling was also greater than the planned rig time. Therefore, the operations was a limited success overall. This is attributed to the smaller coiled-tubing size selected, the performance of the jet nozzle used, and the inexperience of the personnel, among other factors. The paper provides the dos and don'ts of RJD, as the first application of RJD in this field and the lessons learned from the field practice, future wells can be drilled with great enough number of laterals, their penetration length and lower cost. Therefore, the planned well productivity would be further enhanced, thereby, full success from the application of the RJD technique can be achieved.

Formation damage caused by organic and inorganic deposition particularly near and around wellbore, can substantially reduce the hydrocarbon production. In depleted oil reservoirs, when reservoir-driving forces are low and in declining stage, even small resistance can restrict the fluid flow resulting in loss of well productivity. Single stage chemical system was designed to restore the oil production of Malaysian oil producers that suffers with complex deposition problems. Extensive well selection activities and laboratory analysis were conducted prior to the well treatment. This paper presents five case studies of treated wells that have been revived or boosted using the single stage chemical system. The well treatment consist of bull-heading a pill of pre-flush to facilitate the action of the main chemical system, followed by the main chemical, soaking for 24 hours and flow back the well. The well treatment job was completed successfully and safely with chemical cost saving of 40%. Post well treatment showed mixed results by instantaneous average production improvement of more than 400% for Well BK1, BK2 and BK3 and 26% production gain for Well BT2. The improved production sustained up to five months before a drop in production back to the old trend. Well BT3 wellbore damage was partially removed with less incremental in terms of gross production post treatment. Primary hypothesis of short sustainability of the post well treatment is likely due to re-deposition of wax within the subsurface environment. Confirmation on this hypothesis is planned through slick line intervention. The instantaneous production gain highlighted the opportunity to replicate the technology with improved method by incorporating the inhibition chemical component to other potential wells that face similar deposition problem through proactive and preventive approach to ensure production sustainability and minimize the number of idle wells.

Drilling long horizontal and multilateral wells in the oil industry helps lower the drawdown, and minimize water or gas coning, which enhances well productivity. Many of these wells are drilled using drill-in fluid (DIF), which is cleaner than conventional mud and so is considered to be less damaging to the formation. The DIF consists of polymers for building the required viscosity to transport cuttings and deposit a filter cake around the wellbore to reduce fluid loss. Most DIFs are composed of starch, cellulose or Xanthan polymers added with bridging agents of calcium carbonates and salt particles. Even though DIF causes less formation damage than conventional mud, damage to target formations can still occur. To remove formation damage caused by DIF, a new chemical technology is tested. The new chemical technology, which breaks up the coherence and integrity of the mudcake and polymer gel, was used for wellbore cleanup with very encouraging results. In addition, the chemical is also an eco-friendly, noncorrosive bio-enzyme and is naturally biodegradable. The chemical disintegrates into its natural elements (carbon, hydrogen, oxygen and nitrogen) after converting the insoluble polymers into water soluble sugars. In addition, the chemical minimizes formation of wormholes like in acid, which helps in keeping the wellbore away from getting connected to fractures/fissures. This paper highlights the technological advantage of using the enzyme based chemical and how homogenous wellbore cleanup/stimulation is achieved, leading to productivity enhancement and sustainable oil production.

The Danish North Sea Halfdan Field is developed with extremely long horizontal wells in a line drive producer/injector pattern. The carbonate reservoir requires successful acid stimulation to maximize the flow potential of the wells. High rate, matrix acidizing, relying on maximum pressure differential and injection rate (MAPDIR) was the initial stimulation process used to treat these wells. 1 Later, this process was continued with the addition of chemical, in-situ viscosifying diverter stages to improve acid placement. Pre-drilled liner completions have been the primary method across the Halfdan field and has been a very cost effective, efficient way to complete the extended laterals required. Multi-discipline pattern reviews are routinely held to review the producer/water injector performance within the field. These reviews included well flow performance, intervention history, stimulation review, caliper/corrosion history, and 4D seismic interpretation. Candidate wells were identified for possible intervention work, conformance, and stimulation opportunities. Although the liner completions were designed to optimize acid placement, increased volumes of in-situ crosslinked acid, with seawater over flush, was used to improve placement. In addition, trials were developed to also include a particulate diverter material in several producing well restimulation treatments. The pressure response and the production gains were very encouraging and this led to additional re-stimulation candidate selection across the field. This paper reviews the outcome of one of these reviews in regards to water injection performance in some parts of the Halfdan Field. Prior to this project, it was typical to stimulate all water injectors with high rate acid treatments and, in some cases, staged volumes of in-situ crosslinked acid for diversion, along with the pre-drilled limited entry liner. The particulate diverter, used on some producers, was soluble at temperatures higher than the bottomhole temperature of the water injectors. This challenge was addressed during the review and a method agreed on to evaluate the effectiveness of the particulate diverter to improve the acid distribution in these water injectors. A project team worked together to produce a design for the re-stimulation treatments and to develop a methodology to use this particulate diverter in a low temperature environment. The team worked through a procedure to flowback the water injector following the re-stimulation treatment. A risk assessment was completed in terms of flowing back into a donor well and simulations were completed to determine that flowback rates were sufficient to return any solid material to surface. The case history is reviewed to present the design and execution of the two water injector re-stimulation treatments. Following the cleanup/flowback of the wells, water injection was re-established to return to pretreatment bottomhole injection pressures. The results of the water injection rates are discussed as well as further plans for similar treatments.

It is common knowledge that over its life-cycle an oil producer or water injector may experience a reduction in near-wellbore permeability or overall fluid connectivity to or from the reservoir from in-wellbore impediments that negatively impact productivity or injection. Such permeability reductions or fluid connectivity losses are often related to near-wellbore damage or ‘skin’ or in-well damage induced by fill, scales, waxes, asphaltene or other blocking mechanisms. In recent years an increasing number of coiled tubing ("CT") stimulation and cleanout interventions has led to the advancement of downhole tools focused on remediating such damage mechanisms. One such development that has been successfully deployed to re-establish water injection rates for reservoir pressure support in oil field production operations is a multi-directional, cavitational-based fluid pulsing tool that provides a hydro-mechanical means to both remove detritus materials from the immediate wellbore but also stimulate the near-wellbore region.

Subsurface barrier valves such as a formation isolation valves (FIVs) isolate the formation from the production bore after the first perforation and the lower completion has been installed. This enables installation of the upper completion and in some cases multiple perforation runs before the well starts producing. During this time, they protect the formation from fluid loss and pressures by acting as a bi-directional fluid barrier. In addition to reduced rig time, a key advantage of FIVs is reduced intervention costs. FIVs can be openend and closed multiple times as required, mechanically with an intervention tool such as a primary shifting tool (PST) ( Fig. 1 ). The conveyance method for PSTs can be on coiled tubing, work string, perforating string, or wireline (using a tractor and stroker) to open and close FIVs. PSTs then must reliably engage and release from shifting profiles in the FIVs to operate the valve and release from the profile after successful valve actuation. Hence design of the PST is critical for relaible FIV operation. In the event of an emergency where the shifting profile in the tool is unable to release from the engaging profile in the FIV, it is critical to have an emergency release feature inherent in the PST that can enable release of the tool yet not damage the FIV. A novel methodology was developed to design PSTs to enable emergency release if required, through controlled plastic deformation at loads below work string shear limitation. This methodology also avoids fracturing of PST components as free-hanging pieces could be caught in the wellbore while pulling out the tool from the well after emergency release.