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In earlier days, the main technology developments were mostly related to the materials, such as fluids and proppants, and their characterizations. In recent years, more advancements have been made in tools, engineering processes, and analyses. In a cased-hole fracturing treatment, perforating plays a critical role to the success of the job, though it is often overlooked because perforations are visualized as holes with empty tunnel behind the pipe. Any damage is irrelevant because fracturing will simply bypass the damage. In fact, a shaped charge is made of metal liner and case with explosive loaded in between.
The post-acid-fractured well productivity index (PI) showed the high quality of the stimulation performed in a challenging environment, demonstrating the effectiveness of the new diversion system for creating selective fractures in a horizontal wellbore with multiple perforation clusters. Completion of deep HP/HT carbonate formations in northern Kuwait in overpressured environments comprising interbedded carbonate bodies, complex tectonics, and stress variations resulting in strike/slip or reserve fault regimes is challenging for operator and service companies. Because of the low-permeability conditions, it is necessary to generate long and conductive fractures to produce the reservoir effectively. Additionally, this aggressive fracture-stimulation requirement needs to overcome the high-working-pressure limitations of the completion, in addition to the nature and corrosiveness of the produced hydrocarbon, which makes selection of the proper stimulation reactive-fluid system important. These challenges are even more crucial in cases having drilling and completions issues.
Abstract Acid fracturing has been an integral part of reservoir development strategies for carbonate reservoirs as mechanical and chemical means of bypassing formation damage enhances productivity. Over the past few years, acid fracturing has significantly increased targeting more carbonate reservoirs. There is a need to fully address the heterogeneous petrophysical and geomechanical properties of target reservoirs, which adversely affects the stimulation efficiency and production if fluids are not properly designed. When injecting stimulation fluids to fracture the reservoir rock, the fluid is prone to traveling along the path of least resistance, and consequently less permeable zones and high stress reservoir rock receive treatments that could be further improved or enhanced. Accordingly, this drives the industry to continuously develop high performance chemical dynamic diverter systems. To ensure an effective and sufficient acid fracturing is achieved when treating long intervals of perforated clusters or openhole horizontal wells. Recent advancements in diversion technology utilize various forms of degradable particles, where they serve to provide a temporary bridge, which is either inside the existing fracture or the perforation entrance. This allows for intentionally forming a low permeability pack, allowing the pressure inside the fracture to increase and redirect the next stage of fluid to the zone having a higher degree of stress that has not yet been covered by the fracture. The objective is to increase the fracture complexity, particularly in vertical wells where there is big variation in geomechanical properties of the formation. To gain a deeper understanding of the performance of these diverters, a simulation study was conducted to analyze and compare the efficiency of particulate diverters used in two pilot wells. Fracture modelling and sensitivity analysis were also performed to understand the effect of diverters on the fracture geometry. To match the actual treatments, modelling validation and control were achieved through utilization of field data such as production logging, temperature surveys and pressure buildup tests. The study determined that the success of the particulate diverter employed for the fracturing application is heavily dependent and governed by the geomechanical properties of the treated zone and the ability of the diverter to overcome the stress difference in the stimulated interval. Optimization of the diverter design and degradation profile is still needed to improve and achieve the best stimulation efficiency.
Abstract Tight carbonate gas reservoirs require stimulation in order to establish commercial viability. In order for the development plan to be considered effective and successful, two main parameters have to be studied and evaluated, time, and cost. The conventional method to stimulate tight carbonate reservoirs is bull heading acid fracturing treatment, which is costly and time consuming for multi stages wells, not excluding the high treatment pressure requirement and risk associated with it. Conventional plug and perf technique includes e-line operations to perforate with guns, acid fracturing treatment by bullheading, and e-line operations to set plugs for every single stage. A novel acid-soluble abrasive material, was implanted and tested as an economical and time effective alternative solution. The technique involves perforating through cemented liners utilizing the abrasive material flowed by low volume acid surgesqueeze. By using this technique time and cost associated with the conventional plug and perf technique, can be reduced and achieve even better result with less cost and time. The wells that were stimulated with this technique, were tested and proven superior in terms of production rate over the conventional plug and perf technique in the short term. More evaluation to be done on the wells over the long term and evaluate if they are going to sustain the production over time. This paper provides a brief summary about the technique. Also, will discuss in details, the cost and time effectiveness, the short term result, and compare it with the conventional plug and perf technique.
Ordinary acid fracturing treatments cannot deliver consistent production results in low-pressure carbonate reservoirs. The reservoir pressure is not sufficient to flow back the large volume of treating fluids from the formation after the treatment, thus minimizing the benefits of performed acid fracturing. The use of foamed acid fracturing fluids will provide additional energy that will help to enhance flowback and push treating fluids out from the reservoir during post-fracturing flowback operation. There are two types of gaseous phase that are commonly used to foam the fluids for stimulation treatments: nitrogen (N2) and carbon dioxide (CO2). N2 is an inert gas; it is widely available and therefore the most frequently used. CO2 is more soluble in water than N2; therefore, more CO2 is required to saturate the liquid and create the foam. CO2 has more expansion during flowback, which aids in total fluid recovery. Additionally, the solubilized portion of CO2 reduces the interfacial tension of the fracturing fluid.
A deep high-temperature carbonate reservoir typically requires acid fracturing treatment to produce at economic gas rates. When reservoir pressure declines over time, foamed acid fracturing treatment becomes the preferred stimulation option. Both types of the gaseous phase show good success. The multiple case studies suggest that foamed acid fracturing resulted in easier flowback initiation and better well productivity compared to regular acid fracturing. Moreover, CO2-based foams provided better results compared to N2 foams, especially in horizontal wells completed with multiple acid fracturing stages within the same reservoir. The specific fracturing fluid was deployed to use CO2 foam in the wells with high bottomhole temperatures up to 300°F. The innovative CO2 foam chemistry enables formulating non-crosslinked gels that deliver viscosity equal to or better than the industry-standard foams of low-pH guar crosslinked fracturing fluids. This fluid delivers those results at significantly lower polymer loadings and with a reduced number of additives, thus improving the operational aspect and increasing well productivity. Another noticed benefit of foamed acid fracturing with CO2 is the easier achievement of higher foam quality at bottomhole conditions. N2 is pumped in its gaseous phase and requires specific pumping units with limited pressure and rate capacity. In contrast, CO2 is pumped in its liquid phase through the common fracturing pumping units; therefore, a significantly higher pumping rate of the gaseous phase can be achieved with minimum additional equipment.
Particulate diversions are widely used for stimulation treatments. Usual field practice is to increase the volume of solid particles to create a considerable pressure response. However, an excessive dose of particles challenges particle removal and results in unexpectedly longer clean-up time. Self-degradable particulate diverter systems can overcome this shortcoming. The current study investigates the mechanisms of self-degradable particle transport and progressive clogging involved in fluid diversion. Engineering solutions and case studies for applying this new diversion technology in fracturing unconventional formations and acidizing carbonate reservoirs are discussed separately.
An integrated workflow and numerical models have been established and verified with experimental data and field experience. In the hydraulic fracture stimulation analysis, a wellbore-scale computational fluid dynamics and discrete element method (CFD-DEM) is employed to understand the physics of particle slurry transport and particle jamming at an opening. A three-dimensional reservoir-scale simulator is used and coupled with particulate diversion mechanisms for fracturing. To simulate the carbonate-acidizing procedure, an in-house numerical engine was developed and used to design the diversion of acidic fluid. The stimulated reservoir extent and associated production are predicted to compare the fluid diversion efficiency between various designs and to show the robustness and effectiveness of engineered particle designs. Two field data sets are utilized to demonstrate the applications of new particulate diverters in hydraulic fracturing and matrix acidizing respectively.
Analysis suggests that the success of the new diverter system application is governed by the particle characteristics (size, shape, ratio and concentration) and diverter slurry displacement (rate, viscosity and volume of displacing fluid). The models and workflows are capable of designing fit-for-purpose diverters and their application in different stimulations, including both hydraulic fracturing and matrix acidizing. As demonstrated in our studies, non-engineered designs could result in low fluid-diversion efficiency or even failure of reservoir stimulations. Engineered self-degradable particulate diverters can plug the openings (including perforations and induced wormholes) and withstand differential pressure to divert stimulation fluid (either fracturing slurry or acidic fluid) into under-stimulated regions for effective fracturing and acidizing.
According to our case studies, particulate diverters can be designed to enhance fluid diversion efficiency and optimize the use of particles. The case studies demonstrate the practical applicability and advantages of using self-degradable particulate diverters in both hydraulic fracturing and matrix acidizing operations. The integrated workflow and analysis proved useful to guide the field executions for successful fluid diversions.
Abstract Gas-bearing carbonate reservoirs in moderate to low permeability reservoirs have been targets for acid fracturing treatments in the Middle East. These formations typically exhibit high temperatures, medium to low porosity, and high heterogeneity in terms of lithology and reservoir properties. The heterogeneity dictates completion strategy, with multiple perforated intervals across large gross height in vertical wells with subsequent acid fracturing treatments that aim to cover all perforated intervals in a single treatment. But due to differences in lithology, intervals with high dolomite content are less likely to receive stimulation due to higher stress and reduced acid reactivity. Temperature logs performed on many wells after conventional acid fracturing treatments showed that these perforated intervals accept only a small amount of treating fluids, compared to intervals perforated in clean limestone. An efficient, non-damaging, near-wellbore diverter is required to efficient treat all intervals and improve productivity in such wells. The objective is to stimulate all existed intervals in a single pumping operation, regardless of reservoir heterogeneity, by using degradable diverting materials to temporarily isolate created fractures and redirect the flow to untreated areas. The diversion material used is a composite pill comprising a proprietary blend of degradable fibers and multimodal particles, designed to provide an effective isolation plug at the face of the reservoir in a consistent manner. Fibers are added to ensure the integrity of the diversion pills during delivery and to enhance the bridging mechanism. The use of fibers allows minimizing required diverter volume to few barrels and engineered multimodal diverting materials allow having very strong diversion pressure with small amount of the material. The process increases operational efficiency, well productivity, and estimated ultimate recovery. The materials used to provide temporary isolation have proprietary formulation that degrades within hours or days, depending on bottomhole temperature, with no need of intervention or pumping chemicals to break down the system. Two pilot treatments with degradable diverter were conducted in high temperature high pressure carbonate reservoirs. Extensive measures were undertaken to evaluate the treatments, including pressure analysis, separator tests, temperature logs, production log (PLT), pressure build up (PBU), and nodal analysis. Overall, the measurents and analysis of the treatments proved the efficiency of the degradable diverter for vertical wells: sharp pressure increase up to 1,600 psi when pills arrived at perforation; cooldown effects in all intervals on the post-fracturing temperature logs ensuring uniform distribution of the acid; high flowback gas rates, substantially higher than those of offset wells treated without the diverter; fracture response and signature observed on PBU data; PLT contribution from most of the perforated intervals confirming that treatments penetrated all intervals of interest; and nodal analysis with good production match showed long etched fracture half-length - a preferred fracture geometry for tight reservoirs.
Sierra, Leopoldo (Halliburton) | Alboueshi, Alaa Eldine (Halliburton) | Elmofti, Mohamed (Halliburton) | Eid, Walid (Halliburton) | Sadeddin, Salma (Halliburton) | Allam, Ahmed (Halliburton) | Al Othman, Mohamed (KOC) | Ahmed, Zamzam (KOC) | Fidan, Erkan (KOC) | Al-Zaidani, Ibrahim (KOC) | Nilotpaul, Neoq (KOC) | Ashkanani, Meshari (KOC) | Buhamad, Ali (KOC) | Al-Dousari, Mohammed Abdullah (KOC) | Ahmed, Abdul-Samad Mohammed (KOC) | Al-Matrouk, Yousef (KOC)
The case history presented in this paper describes the performance of an acid fracture intervention in a HP/HT well where, because of a number of problems encountered during the well construction stage, this intervention was the last procedure considered to evaluate the productivity of a Marrat formation well. In view of the stimulation challenges encountered, the architecture of the wellbore, and the intervention stimulation requirement to evaluate the productivity of the horizontal well completed in the Marrat formation, it was necessary to change the proppant fracture stimulation technique originally planned. Instead, it was decided that a selective acid fracture stimulation would be performed in the prospective part of the horizontal section where three long perforation clusters had been placed. Acidizing fracture stimulation was performed in one intervention using a next-generation liquid and soluble solid diversion system that enabled the generation of one selective fracture per perforation cluster. The planned acidizing fracture stimulation process was implemented properly in the field in accordance with the design constraints. The reactive fluid system diversion and the generation of a new fracture when the diversion system reached the perforation were clearly observed. The post-acid fractured well productivity index (PI) showed the high quality of the stimulation performed in a challenging environment, demonstrating the effectiveness of the new diversion system for creating selective fractures in a horizontal wellbore with multiple perforation clusters. Considering the well's architecture, HP/HT nature, and single intervention requirement, the case study documented in the paper can be helpful in the decision-making process when selecting a proper stimulation technique for challenging conditions. The effectiveness of the new diversion systems is also discussed.
Abstract Chevron Iraq Limited carried out a drill-stem test (DST) campaign in the Kurdistan Region of Iraq starting in year 2014. Several reservoirs with varying characteristics were targeted. The designs of the executed stimulation treatments were based on reservoir and fluid information acquired during the drilling phase. The complex carbonate formations presented uncertainties in terms of the formation fluids, lithology, and the type and severity of formation damage that may have been present. This was a challenge toward stimulation fluids design and treatment placement. With the objective of optimizing stimulation treatments in the tested intervals, stimulation design best practices were applied and a three different stimulation methods were utilized including a hybrid matrix acidizing / acid fracturing approach. In order to design the treatments, open hole logs, drilling fluids damage from mud losses, fluids compatibility, fracture pressures, placement rates, and other well conditions were considered. The bottom-hole pressure recording and the production results measured through the DST operations enabled an in-depth evaluation of the acid response as the campaign progressed and provided valuable data for optimization of the stimulation strategy from one treatment to the next. This paper explains the stimulation fluids selection, quality assurance, fluids placement design, the three differing stimulation strategies applied and rationale for applying them, operational execution, and evaluation of the results in addition to the lessons learned for the way forward. This will be of interest and may be beneficial to those with similar projects involving complex carbonate reservoirs in northern Iraq and other areas of the world.
Abstract This paper highlights the difficulties and limitations faced along with the respective solutions proposed and executed during the zonal isolation of a highly permeable, naturally fractured and acidized carbonate reservoir during its exploration phase after having performed an extended pressure buildup (PBU) test on a remote field in Saudi Arabia. To accurately compute the hydrocarbon reserves of a particular region, operators must explore new reservoirs in remote areas, in both challenging offshore and onshore environments, to decide future field development. The services performed on these wells include drill-stem test (DST) completions, underbalance perforation, acid stimulation, placing downhole gauges/shut-in tools, extended flowback and PBU periods, and final zonal isolation. In this candidate well, the operator wanted to test three zones, further performing high-rate acid fractures on the lower two zones to be able to determine commercial hydrocarbon gas rates. The first major challenge was for zonal isolation of the lowest zone, expected to be a highly fractured zone that might also be stimulated. A cement plug was designed to be deployed by means of coiled tubing (CT) for accurate placement and depth control. The added challenge in this exploratory well was to plug any wellbore channels and highly permeable fractured streaks in the lowest reservoir zone after acid stimulation and reservoir evaluation were completed while preventing excessive cement fluid loss into the zone from the cement volume that would challenge the plug effectiveness. This paper explains the innovative solution devised for this well, including the job execution and elaborating on the combination of CT intervention, carefully designed chemical blends, cement fluid handling systems, and implementation of best practices to deliver a successful zonal abandonment. The operation consisted of three runs: the first used a lead batch of an organically crosslinked polymer with loss circulation material (LCM) in the solution; the second was performed for cleanout, displacement, and permanent cement slurry placement; and, after waiting on cement (WOC), the third was used to tag the top of cement (TOC) and perform a pressure test. The organically crosslinked polymer with LCM solids served to bridge off the perforation tunnels and potential fractures in the rock so that a precise volume of cement plug slurry could be pumped safely and accurately.