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.

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.

Coring is a considerably costly drilling operation, but vital to retrieve valuable sources of ground-truth data in the oil and gas industry. To justify the high cost of this operation, essentially, cores should not undergo jamming and mechanical damage. Core jamming not only indicates an unprecedented termination of the operation, but also causes severe damage to the core column already taken in the barrel. This means that the cores cannot be retrieved with sufficient key performance indicators (KPIs); thus, it would not reliably represent reservoir properties. Reaching this significant target can be ensured not only by proper design, but also by online monitoring and investigation of the drilling parameters. This investigation predicated on several case studies in the Middle East to identify the effect of imperfect decisions made by the driller. Based on the experience and observations, the paper provides practical recommendations to alleviate the impact of such negative actions. The drilling parameters observed in the mud logging data of six coring case studies (of several runs from three wells in carbonate reservoirs) were investigated at the depth interval just prior to jamming occurrence. These parameters consist of rate of penetration (ROP), torque, weight on the bit (WOB), rotary speed (revolutions per minute, RPM), circulation rate, and standpipe pressure (SPP). In this work, a main cause of the core jamming occurrences is discussed; that is, the improper drilling parameters application, as mismanaged by the driller. Finally, as indications of jamming, sudden variations of the drilling parameters at the specified depth were investigated. Such study can contributeto the better monitoring for future coring operations. Based on the observations in six case studies in three wells , WOB was identified as the most significant reason causing core jamming; that is, jamming occurred when the WOB was not steadily maintained on the bit probably due to the driller’s inexperience, shift change, etc. For monitoring, torque decrease, ROP decrease, and SPP variation or decrease (following initial increases) were identified as indications of core jamming. Torque showed to be a significant parameter forjamming detection when it decreases or its trend becomes completely straight, i.e., without any variations, indicating that the core head may not be in contact with the formation. Next, drilling issues during coring (such as pump failure) can contribute to subsequent jamming. The case studies in this paper provide several observations and indications of core jamming occurrences in a limestone reservoir which can be attributed to non-optimized drilling parameters. The paper also provides several practical recommendations and measures to prevent core jamming and core damage.

In recent years, shape memory polymer materials (SMP) and conformable sand control technology have shown significant advantages to conventional gravel packing or expandable screen solutions by providing the right combination of operational simplicity, total conformance, wellbore stability, and superior filtration required for long-term sand control and effective production inflow from reservoirs. Contrary to gravel packing that requires most of the wellbore length to be covered by screen to help dehydrate the slurry, the shape memory material may be placed selectively across the sweet spots. This has led to the question about how much of the intervals would need to be covered to get maximum productivity with the minimum SMP coverage, thereby impacting the overall completion cost. This paper utilizes reservoir modeling based well completion simulation to evaluate the impact of the SMP cartridge design configuration and reservoir properties on well production performance and provide optimized screen design solutions to maximize well production in oil reservoirs. The reservoir model and horizontal well completion with the SMP cartridge modules are built in a reservoir simulator. Three categories of simulation cases are performed to investigate their impact on production: the number of cartridges per well segment, cartridge locations and spacing, and reservoir properties such as permeability and capacity. These case results are compared with a base case where conventional standalone screen is used. The comparisons are used to define maximized and/or most economical sand control solutions. The results provide an effective optimization solution for maximized cumulative well production in oil reservoirs. In low rate wells, the simulation results also provide a more economical solution for cost sensitive well completions. Simulation results demonstrate significant production improvements with conformable SMP technology over conventional screens and provide a useful workflow to optimize completion designs for different reservoirs.

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.

Most wells in carbonate reservoirs are stimulated. Due to low cost and simpler operations, acid stimulation methods are usually preferred if they are sufficient. Matrix acidizing can effectively stimulate carbonate reservoirs, often resulting in skin factors on the order of -3 to -4. In low confining stress and hard rocks, acid fracturing can yield better results than matrix acidizing. However, acid fracturing is less effective in high permeability, high confining stress, or soft rocks. There is a combination of parameters, among them permeability, confining stress, and rock geomechanical properties, that can be used as a criterion to decide between matrix acidizing and acid fracturing which is the best acid stimulation technique for a given scenario. This study compares the productivity of matrix acidized and acid fractured wells in carbonate reservoirs. The criterion used to decide the preferred method is the largest productivity obtained using the same volume of acid for both operations. The productivity of the acid fractured wells is estimated using a fully-coupled acid fracturing simulator, which integrates the geomechanics (fracture propagation), pad and acid transport, heat transfer, temperature effect on reaction rate, effect of wormhole propagation on acid leakoff, and finally calculates the well productivity by simulating the flow in the reservoir towards the acid fracture. Using this simulator, the acid fracturing operation is optimized, resulting in the operational conditions (injection rate, type of fluid, amount of pad, etc) that lead to the best possible acid fracture that can be created with a given amount of acid. The productivity of the matrix acidized wells is estimated using the most recent wormhole propagation models upscaled to field conditions. Results are presented for different types of rock and reservoir scenarios, such as shallow and deep reservoirs, soft and hard limestones, chalks, and dolomites. For each type of reservoir rock and confining stress, there is a cut-off permeability below which acid fracturing results in a more productive well; above this cut-off permeability, matrix acidizing should be preferred. This result agrees with the general industry practice, and the estimated productivity agrees with the results obtained in the field. However, the value of the cut-off permeability changes for each case, and simple equations for calculating it are presented. For example, for harder rocks or shallower reservoirs, acid fracturing is more efficient up to higher permeabilities than in softer rockers or at deeper depths. This method provides an engineered criterion to decide the best acid stimulation method for a given carbonate reservoir. The decision criterion is presented for several different scenarios. A simplified concise analytical decision criterion is also presented: a single dimensionless number that incorporates all pertinent reservoir properties and determines which stimulation method yields the most productive well, without needing any simulations.

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.

Water breakthrough (WBT) in the horizontal wells often leads to water flooding in the well, especially to those heavy oil reservoirs in reef limestone carbonate. The excessive water production from the hydrocarbon producing horizontal wells can adversely affect the economic life of the well, furthermore this could result in the well permanent abandonment. Nowadays, no effective methods of water control are available for the similar reservoirs, traditional water control methods have three technology barriers: (1) can not accurately locate the WBT positions;(2) difficulty of identifying the wellbore completion, fluid, and nearby formation conditions;(3) Not being designed to control water from new water breakthrough points. This paper shows a newly developed water control technology by using continuous Packed-off double water control technology (CPI). It was successfully implemented in a well of a fractured reef limestone oil field in South China Sea. This technology completely overcome the above shortcomings of traditional water control methods. The mechanism is to pack patent particles into the wellbore and near-wellbore fractures to create a double "artificial well wall". It suppresses radial and axial turbulence effectively. The operation procedure of CPI water control method is simple. It has been proven with lower cost and longer effective duration of controlling water, which can greatly increase oil recovery. Results show that the water content in the well of CPI water control is only 10% to 33% of the adjacent wells at the same geological layers. The initial oil water ratio in the CPI well is 13, which is ten times better than the adjacent wells. After 2 months' production, the water content of CPI well is 13.3%, compared to 67%, 62%, and 89% of the adjacent wells.

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.

Controlling lost circulation during drilling operations in a reservoir prone to losses is typically remedied by cement squeezing or plug setting. The aim being to minimize or stop drilling fluid losses and to regain full returns at surface, and to affect wellbore integrity. Different placement methods of cement plugs have been discussed in detail in the literature, except for the ‘level-off’ method, which is particularly effective for curing complete loss circulation cases. Following the mathematical modeling of this cement plug placement method, its design, procedure and execution are discussed, together with some successful field cases, both drilling and workover situations in highly-fractured carbonate reservoirs in the Middle East. Using drill pipe and an installed a Retrievable-Test-Treat-Squeeze (RTTS) packer, with some spacing from the loss zone, the method entails that the cement slurry is allowed to drop by gravity in order to cure lost circulation. As the column of fluid, mud and slurry in the well exceeds formation pore pressure, i.e. overbalanced conditions, a volume of acid-soluble cement slurry is allowed to slowly drop and freely penetrate the formation, i.e. through its fractures or caverns. During the penetration of this viscous slurry into the loss zone, the cement can set and the fracture or fissure openings are plugged. In addition, to minimize or prevent further losses, this cementing technique may also mitigate formation damage of adjacent zones. Presented are detailed design calculations for the level-off placement technique: determination of required cement slurry and displacement volumes, and recommended displacement and RTTS packer setting depths. The expected depth of the top of cement is estimated. The design parameters are compared with field cases and explanations are given for possible discrepancies. Detailed field procedures and execution are also presented. This is the first known, detailed description and modelling of the level-off cement placement technique in the literature.

Whilst drilling the 12 ½" and 8 ½" sections on a HPHT field in the North Sea, fluid losses were encountered which required the pumping of high concentration Loss Circulation Material (LCM) as well as multiple ‘through the bit’ cement squeezes. The reservoir had been under production for many years and was now at a point where it had significantly depleted and the formation was very delicate, making it easily subjected to fracturing. Losses were expected to be an upcoming challenge as the mud weight window was so narrow and due to the HPHT rating of the offshore reservoir and the fractured nature of the geology, this posed as a serious risk that required pre-planned mitigation. The ability to pump ultra-high LCM concentrations was discussed in pre-planning as being one of the key mitigation strategies to stemming losses. However, it was thought that pumping LCM would block a typical MWD pulser due to the narrow geometries of the flow paths within. Successful onshore testing was conducted prior to drilling operations to prove that the MWD pulser selected had the ability to permit the flow of ultra-high concentrations of LCM. A closed loop system was created onshore and LCM with concentrations up to 420kg/m 3 (147lbs/bbl) was pumped through the MWD tool without blocking it up and with full functionality throughout. This gave the operator the confidence to pump LCM through the MWD tools, if required in the field. The use of an MPD (Managed Pressure Drilling) system was also required to keep the equivalent circulating density within the tight mud weight window by maintaining a constant bottom-hole pressure through the application of Surface Back-Pressure (SBP). This was critical as the well, when static, was underbalanced. The incorporation of MPD also gave the operator the ability to ‘squeeze’ LCM/cement into the well and formation by applying surface back pressure during ‘through the bit’ LCM/cement jobs. During field operations, the operator did go on to pump a 320 kg/m 3 (112 lbs/bbl) LCM pill through the MWD tool without plugging during a loss scenario. Pumping LCM through the MWD tool reinforced the formation and enlarged the mud weight window from <0.01sg to 0.03sg allowing operations to continue. In addition, muliple "through the bit" MPD LCM/cement squeezes were conducted on two wells in the same field with no negative effect on any of the MWD tools. The partnership between the MWD and MPD systems formed a key part of the losses management. The MWD system could identify exactly what downhole pressure losses were seen at, which was then transmitted by the pulser to the surface. The MPD system would then use an algorithm based calculation to apply the exact required SBP to maintain a constant bottomhole pressure, that was within the mud window. This provided the operator a safe and efficient solution to continue to the target depth in a very challenging narrow margin well.

Wellbore instability is caused by the radical change in the mechanical strength as well as chemical and physical alterations when exposed to drilling fluids. Unscheduled events that are related to wellbore instability account for more than 10% of the drilling cost, which is estimated to one billion dollars per annual cost. Understanding shale-drilling fluid interaction plays a key role in minimizing drilling problems in unconventional resources. The need for providing a more suitable drilling fluid system for drilling operations in unconventional resources is growing. The major consequences of improper fluid selection include bit-balling, hole sloughing, and most importantly low drilling rates. This study will evaluate the effect of different inhibitive drilling fluid systems on shale drilling performance. The mud systems use in this study include cesium formate, KCl based mud systems, and a conventional water-based mud. The conventional water-based mud is used as reference fluid. An innovative HPHT drilling simulator is used to perform real-time drilling operations on cylindrical shale core samples obtained from the Tuscaloosa Marine Shale (TMS). The process involved simulating real-time drilling operation at downhole conditions where different fluids served as drilling fluid. A comparative analysis of the impact of each drilling fluid systems on the drilling performance as then performed. The analysis focused on drilling parameters such as rate of penetration, torque, and friction factor during drilling. This paper evaluates the compatibility between different fluid systems and shale formations. The paper also provides an overview of the effect of the inhibitive mud systems on drilling performance. The inhibitive muds systems (KCl based fluids and cesium formate) provided improved drilling performance compared to conventional water-based mud.

Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations and is the base acid commonly paired with others such as hydrofluoric (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature can make HCl a poor choice. Alternatively, weaker and less corrosive chemicals such as organic acids can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids. This review includes various laboratory evaluation tests and field cases which outline the usage of organic acids for formation damage removal and dissolution. Rotating disk apparatus results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, core-flooding, Inductively Coupled Plasma (ICP), X-Ray Diffraction (XRD), and Scanning Electron Microscope Diffraction (SEM) tests. Due to their retardation performance, organic acids have been used along with mineral acids or as a stand-alone solution for high-temperature applications. However, the main drawback of these acids is the solubility of reaction product salts. In terms of conducting dominant wormhole tests and low corrosion rating, organic acids with low concentrations show good results. Organic acids have also been utilized in other applications. For instance, formic acid is used as an intensifier to reduce the corrosion rate due to HCl in high-temperature operations. Acetic and lactic acids can be used to dissolve drilling mud filter cakes. Citric acid is commonly used as an iron sequestering agent. This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically, in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.

Loss circulation encountered in highly fractured formations, depleted reservoir, or HP/HT intervals is the root cause of many problems plaguing the oil and gas sector for many years. High pore pressure narrows the window of safe drilling, while in depleted reservoir fracture pressure is remarkably reduced, which may lead to a lower pressure-bearing capacity. Therefore, a proper predrill wellbore strengthening strategy is needed to anticipate wellbore issues and design drilling fluids that strengthen unstable formations. This study benefits from the successful applications of polymers in water shut-off. Whereas polymers are used to entirely plugs high water productive zones, the flowing polymer-based mud (PBM) is proposed and evaluated to enhance wellbore strengthening. Based on the API drilling fluids testing procedures, varied polyacrylamide/polyethyleneimine PAM/PEI systems were tested and ammonium chloride (NH 4 Cl) is added as a retarder to control gelling time as need. Base fluid formulated with PAM/PEI was optimized to attain the desired rheological properties. Weighting and other commercial essential additives were also added, and the formula is tested for rheology, stability, and sealing efficacy. Our proposed PBM formula with proper concentration of polymer in water and optimized PAM to PEI ratio is found to be highly competitive in comparison with the conventional methods of loss circulation prevention and wellbore strengthening techniques. This paper introduces an innovative design for a flowing polymer-based mud (PBM) for wellbore strengthening and provides wide-range of assessment. Moreover, the essential rheological characteristics revealed in this study for several PAM/PEI mud systems under various conditions can set the stage for wide application of these muds globally where tremendous reduction in drilling non-productive time (NPT) can be achieved.

The execution of Open Hole Horizontal Gravel Packs (OHHGP) in ultra-deep waters (greater than 1500m) demands the use of the best technologies available. For the Atlanta Project, a detailed description of the first two wells successfully completed with OHHGP in the field, was provided in previous papers (OTC-25813, SPE-174893, SPE-174896). The third Atlanta well faced a new challenge: the integration of AICD technology (Autonomous Inflow Control Device) in the gravel pack screens. Due to the restriction imposed to the flow through the screens by the AICDs, the resulting pumping pressure and associated ECD (Equivalent Circulating Density) is increased, further reducing the already narrow operational window, which is common for reservoirs in such water depths. The use of AICD technology, which imposes an additional pressure drop to the aqueous fluid flow, further increases the pumping pressure, making conventional gravel packing strategies and procedures unfeasible. To overcome these new challenges, dozens of simulations were performed to address the new challenge and an innovative screen configuration was adopted to facilitate effective gravel pack placement while retaining the necessary fluid flow restriction of the AICD operating as per the simulation design during well production. Additionally, to ensure effective and complete gravel pack efficiency, a new pumping procedure, incorporating the use of three different proppant strategies, was implemented. By introducing these innovations, the third Atlanta well was 100% packed and the expected PI was obtained. Long-term performance, with the aid of tracers installed in the screens, is being evaluated. This paper will detail all the planning and execution phases that enabled completion of the first open hole gravel pack with AWES RP T2 AICDs in ultra-deep waters. Also in this paper, the production evaluation data is analyzed.

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.

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.

Production of heavy oil reservoirs are increasing due to the limitation in conventional resources. Despite the availability of different technologies and methods for recovery and enhancing the oil production from heavy oil reservoirs, we need to consider the oil production from these reservoirs with their particular rock and fluid chemical characteristics to prevent serious formation damage during drilling the reservoir. Heavy oil is intend to build strong microemulsions that blocks the reservoir pores. Unfortunately, this concept is missed and the heavy oil properties and its viscosity are considered as the main problems. This paper studies the formation damage and mitigation in heavy oil reservoirs. Drilling fluid is the first non-indigenous fluid to contact the formation and thus, it provides the first opportunity for causing permeability damage. The key point in formation damage control is to minimize the invasion zone into the reservoir section. Controlling the chemical reactions between invaded fluid type and heavy oil along with the changes in rock properties plays an important role in emulsion blocking which is the main cause of formation damage in these reservoirs. In addition, we need to consider other parameters such as lithology and shale dispersant which can be the other source of damage to plug the porous media. Both Laboratory pilot tests and field application proves the effect and performance of drill-in-fluid in the heavy oil reservoirs. The designed high performance reservoir compatible drilling fluid replaced oil based mud which reduced formation damage by keeping the production index at acceptable and higher level comparing to previously drilled wells. Furthermore, the paper discusses the designed criteria including formulation, properties and applications of the fluid in detail by comparing lab and field data to prove the effect of Drill-in-Fluid effect on the well production performance. It was observed that the high performance, reservoir compatible drilling fluid system, successfully minimized formation damage by minimizing fluid loss invasion into the reservoir comparing with conventional OBM with lower skin factor. This recorded a higher productivity index up to 10 times which is a unique achievement without stimulation. The oil production rate of the nominated well increased more than that of the nearby wells.

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.