During plug-and-perf zipper fracturing operations, the capture of incorrect perforation and frac plug depths plagues the future use of this data. Production models currently run on the assumptions of where stage boundaries and perforations should be - not using inputs of where they are. The entry points to the reservoir and stimulation schedule may have left considerable bypassed pay. These models may not require calibration, they simply required accurate data inputs from the onset - or better yet, on-the-fly corrections to access the entire pay zone. A collaborative project started with an operator need to auto-import wireline perforation and frac plug setting depths into an industry recognized wellsite reporting software. The project then revealed itself to be much more – an exercise in ensuring quality depth data from site. This is a game-changing tool for service companies and operators alike. Unique automation capabilities were developed that unified several processes and IIOT data on a completions site.

Coiled tubing (CT) equipped with fiber optics and real-time downhole telemetry and a fit-for-purpose CT tower were used in underbalanced perforating operations in six wells in Indonesia; each operation involved 800 ft of perforating guns, and each was completed in a single trip. The reservoir is thick, with high permeability and characterized by high content of CO 2 and H 2 S. The underbalanced perforating technique was deemed fundamental to minimize formation damage in the near-wellbore area, and the campaign was part of a national strategic project to develop a block's main reserve to supply gas to drive the national economy. Each well had to be completed with minimum of an 800-ft perforation interval to deliver an average of 60 MMscf/D gas production for 16 years plateau with up to 34% CO 2 content and 10,000-ppm H 2 S. The traditional method of e-line overbalanced perforating in such harsh environment became inefficient because of the number of runs required, which can be as high as 40 runs per well. CT-conveyed perforating guns and a completion insertion retrieval of equipment under pressure (CIRP) system were chosen to execute the task. The fiber-optic CT real-time telemetry system was selected to improve downhole depth accuracy, confirm the underbalance condition, and provide real-time confirmation when the 800 ft of guns detonated downhole. To execute the six-well campaign safely, a customized 100-ft CT tower was brought into the country. Because this was the first in-country application for fiber-optic-enabled CT in single-trip with an 800-ft underbalanced perforation interval, thorough planning and preparation were critical for a successful campaign. Considering the high gas rate, high CO 2 , and H 2 S content, a downhole lubricator valve was added as additional barrier during undeployment, and an H 2 S and CO 2 inhibitor was used to protect CT string integrity. Another risk mitigation plan was to utilize real-time CT inspection to monitor the CT integrity and condition throughout the job. Slickline deployment was used in first two wells to deploy multiple guns into the well, but this was deemed inefficient. The CT deployment method was used to complete the campaign. The project comprised a total of 2,200 operating hours, 29 CT runs, and 4,969 ft of guns in six trips with 917 ft as the longest interval. All six wells were completed with no HSE events, no automotive incidents, 98% operational efficiency, and 21% faster than planned duration. This successful six-well campaign represents a first in-country application, which contributed to developing this main gas reserve. The campaign provides lessons for job planning and preparation, technology implementation, execution, and continuous improvement, which can be implemented in similar projects in Indonesia and around the region.

This paper details the first implementation of a deep-set downhole hydraulic lubricator valve (DHLV) in Indonesia. This application was implemented in Jambaran field, onshore Central Java as part of Jambaran-Tiung Biru (JTB) national strategic project. Jambaran is a large carbonate gas field development located in proximity to densely populated areas. Since the field's reservoir contains significant concentrations of CO 2 and H 2 S, it was important to design the completions to be able to perforate and test the wells safely without endangering the surrounding area. To produce as per reservoir management strategy, 800 ft of reservoir section drainage was required. Multiple completion designs were considered in the initial stages which included consideration of an open hole completions design, multiple wireline perforating runs and a cased hole live well single trip coiled tubing gun system. The rigless single trip coiled tubing gun deployment system was chosen due to safety and efficiency factors. With a deep set DHLV as the primary barrier in controlling the wells following perforating substantial daily rental cost savings can be realized during perforating operations. JTB field was developed by drilling 5 new well plus 1 re-entry well. The completions design was similar in all 6 wells. A 2 step completion design was utilized, to compensate for life of well tubing movement load, this consisted of a polished bore receptacle and production packer assembly in the lower completion. The 2 nd stage of the completion consisted of 7" × 5-1/2" tubing with Tubing Retrievable Safety Valve (TRSV), DHLV, Permanent Downhole Gauge (PDHG) and production seal assembly. Strategically placing the PDHG below the DHLV enabled monitoring of bottom hole pressure during shut in without use of memory gauges validating the DHLV as primary barrier during gun retrieval. The production seal assembly was tied back into the lower polished bore receptacle that was previously set. The deep-set DHLV enabled the operator to (i) safely run long TCP gun assemblies up to 911 ft of gross gun length per well to perforate the whole well in 1 trip, (ii) POOH guns efficiently with one time bleed off (iii) efficiently initiate the pressure build up phase by shutting in the well against the DHLV as opposed to a surface valve prior to flowing the well and (iv) gun assemblies retrieved without the need to kill the well. After completing and well testing all 6 wells, the benefits of implementing the deep-set DHLV was immediately realized. By perforating underbalanced, omitting the well kill process and immediately proceeding with pressure build up by closing the DHLV resulted in operator savings of approximately 1.5 million USD over the entire rigless completion campaign.

Post frac cleanout and milling operations are considered some of the most critical activities that leverage on the operational benefits of coiled tubing. Therefore, they deserve the highest focus on continuous improvement and planning since the associated efficiency gains are often immediately quantifiable. This paper will focus on the improvement and optimization of post frac cleanout and milling strategies in extremely depleted wells in the Sultanate Of Oman. The gains from such optimization helped improve wells delivery and overall performances. Plug and perf methodology is still the preferred placement method of hydraulic fractures. One of the main challenges in depleted wells is the need for cleanout and plug milling after each stage to avoid risk of CT becoming stuck either differentially due to depletion or mechanically with plug cuttings in case circulation is lost. For years the frac and mill concept was adopted to complete those wells, resulting in frequent delays to frac operations and huge cost impact to the overall project. An efficiency improvement plan was agreed upon to address this particular challenge. A step-by-step strategy improvement plan was developed via in-depth analysis of frac initiation and reservoir characteristics in order to combine together multiple stages of post-frac cleanout and milling activities. This was done through unique software simulations and fluid selection criteria to achieve the lowest possible bottom hole pressure to minimize the losses in addition to the highest possible lifting velocity and best carrying medium conditions. Moreover, the utilization of engineered fluid solutions with foaming agent and foam generator have demonstrated significant added value through enhancement of carrying fluid properties while achieving the lowest possible settling velocity, which in turn lead to the highest possible velocity factor. After completing the agreed optimization plan, a post frac cleanout with 6-plug milling was performed in a single combined stage instead of multiple individual stages. This improvement reduced the overall frac operation for 6 stages from nearly 30-35 days to 19-20 days. Understanding the field and reservoir pressures in addition to fluid selection for both post frac cleanout and milling operation is crucial to successful implementation of this methodology. This achievement was delivered through a collaboration between many different business units from design to execution and it will help Petroleum Development Oman PDO on the future planning of hydraulic fracturing activity. The completion of the entire wells (well delivery) was achieved in a significantly shorter period of time compared to previous wells; this is reflected on actual cost reduction of more than 20% of total cost/AFE.

A shaped charge for wellbore perforation includes a solid metal or powder liner pressed onto a case, sandwiching high explosives which may have varying thermal stability, dictated by the expected time of exposure and bottom hole temperature (BHT). It is common knowledge that post detonation, the liner-jet punctures the gun body and casing, continuing forward to perforate the formation until its eventual collapse. The jet debris is deposited on the crushed zone forming an impermeable skin and a slug at the end of the perforation-tunnel. This reduces fracture conductivity, and thus, production. Here we present a game changing innovation, the development of a shaped charge with a novel responsive liner. The jet created from our novel degradable liner, post detonation punctures the casing and progress to penetrate the formation until an eventual collapse. However, this system is designed so that, during detonation, a water disintegrable reaction product, bulk metallic glasses (BMG) and/or high entropy alloys (HEA), are formed. These degradable BMG/HEA or complexions decorate the grain boundaries and domain interfaces of the impermeable skin lining the crushed zone of the perforation tunnel as amorphous intergranular films (AIFs) and plug at end of the pathway. Interacting with flowback fluids the BMG/HEA promotes grain dropping, disintegrating the liner and carrot leaving behind a clean perforation tunnel, improving fracture conductivity thus enhanced productivity. In addition, a clear perf tunnel has zero skin value. As such, compared to a coated tunnel with gun and charge debris, it needs little or no acid to clean-up. This results in a demarked reduction of formation breakdown pressures with improved economics for the client. Last but not least this leads to cost reduction of authorized field expenditure (AFE) to support optimized performance of completion design allowing for increased production. CLEAR shaped charges have been qualified to customer specifications in field conditions and are ready to be commercialized. An extension of this technology is being applied to design charges for "Big-Hole" perforations, for the Plug and Abandonment (P&A) market where an effective cement squeeze, anchoring a plug effectively seals the wellbore, preventing the leakage of residual hydrocarbon and associated contamination and emissions.

During perforating operations, identifying the orientation of fiber cable accurately is critical for maintaining the integrity of permanently installed fiber.Beyond completions,it alsoprovides insights into how the casings get twisted and how the mechanical stability of the casing is altered as the string is run in the hole. The drilling and completion system is as unique as the aspect ratio and length/diameter is very high. This puzzles the researchers in modeling forces, stresses, stretch, and twists. To aid the accurate prediction in the position of the casing, radial orientation of downhole fiber optic cables canbe used. The clear images obtained by mapping the equipmentoutside thecasing provides not only how the casings get twisted after running in but also provide improved risk mitigation for perforating operations.The orientation angle of the casing versus depthis then analyzed to get the finaltwist and pitch of the twist of the casing. Several wells datawere analyzed to get a comprehensive view of the casingtwist as the casings were run and versus the model prediction. The raw data obtained using the pulsed-eddy current time-domain decay at each station are used for the analysis. Each installed cable detection clamp (CDC) is placed above a casing centralizer located 2' above each joint of casing that had a clamp installed.This simplifies the process of locating the depth of each CDC. A casing collar locator easily identifies the casingjoints.Further, the data are used to find the casing rotation. Several wells showed normal casing rotation of 2–3 wraps along the lateral and onewell showed more than 12 wraps. Several reasons were considered and analyzed including the wellbore spiraling, borehole torsion,and additional mechanical forces applied duringrunning the casing. The coupling of the geometrical and mechanical twist and mechanical stability of the string are discussed in the paper withmathematical underpinnings. In thecase of abnormal prediction, additional mechanical forcesandgeometrical considerations were overlapped and comparedagainst the torque and drag model prediction.It has also beenfound that in some wells where the wellbore torsion washigh,it resulted in a complete twist of 360° atthe heel and in some cases negative trend.

Different applications of fracture bridging and diversion are used regularly in carbonate acid fracturing without an in-depth understanding of the physical phenomena that dominate the processes involved in the bridging and diversion process. The extension of modeling capabilities in conjunction with yard-scale and field-scale experiences will increase our understanding of these processes. A robust multimodal diversion pill and polylactic acid fiber-laden viscous acid were utilized for near-wellbore and far-field bridging, respectively. Numerous field treatments demonstrated the uncertainty of achieving effective diversion. An existing multiphysics model was extended to develop functionalities to model diversions at different scale. Extensive laboratory testing was conducted to understand the scale of bridging and diversion mechanisms. Finally, a bridging yard test was designed, and field case studies were used to integrate all the branches. Field cases showed a diversion pressure up to 4,000 psi depending on perforation strategy, pill volume, and pill seating rate. Correlations showed the interdependence of multiple parameters in diversion processes. The field studies motivated modeling capabilities to simulate the critical diversion processes at high resolution and quality. The model simulates diverting agents that reduce leakoff in the fracture area and their effects on fracture geometry. The approach considers the acid reaction kinetics coupled with geomechanics and fluid transport. Different diverting agent concentrations required for bridging can be modeled effectively. A yard test was designed to confirm the integrity of the pill material through completion valves (minimum inside diameter 9.5 mm) and analyzed with high-resolution imaging. All the theoretical, mathematical, and numerical findings from modeling were integrated with laboratory- and yard-scale experimentation results to develop and validate near-wellbore and far-field diversion modeling. Analytical correlations were formulated from injection rate, particulate material concentration, pill volumes, fracture width, etc., to incorporate and validate the model. This study enhances understanding of the different diversion mechanisms from high-fidelity theoretical modeling approach integrated with a practical experimental view at laboratory and field scale. Current comprehensive research has significant potential to make the modeling approach a reliable method to develop tight carbonate formations around the globe.

A toe initiation sleeve is a tool installed in the toe of a completion liner and is used to establish a flowpath to the reservoir without the use of intervention. Conventional toe initiation sleeves require either intervention or increasing pressure to higher than the liner test pressure to activate. These methods have inherent cost and operational risks. This paper will present the development, qualification, and deployment of a multicycle, time-delay cementable toe initiation sleeve that allows for interventionless activation without exceeding the liner test pressure. This development greatly improves operational efficiency and eliminates risk associated with conventional toe initiation sleeves. A major operator in the North Sea required an ISO V0 rated toe initiation sleeve to be developed and qualified. Design criteria for the tool was identified, and the design was developed based on field-qualified seal technology. Individual component and full-scale validation testing was performed to complete the product qualification, followed by field trials in 2019. With its unique time-delay feature, the newly developed ATS (Advanced Toe Sleeve) allows for an unlimited number of pressure cycles to be performed while also keeping the well V0 barrier in place, and activates at below liner test pressure. This paper will discuss the technology development and implementation project, resulting in ISO 14998 V0-qualified cemented ATS being installed in nearly 40 wells in the same field. This paper will also provide insight into how the ATS provides unique benefits to the operator during various phases of the well's life. Cementing: One moving part and opening sleeve isolated from the inside diameter (ID) allow for pumping darts through the ATS without the risk of opening Setting liner/testing liner: Time-delay features allow for setting liner and testing the liner at higher pressures than ATS opening pressure. Well cleanup/displacing to lower density fluid: Time-delay function allows for opening the ATS at lower pressure than the well has seen during previous operations. Completion: ATS design and qualification grade reduce completion steps and costs for the operator. Stimulation: ATS eliminates the need for intervention, reducing the operational steps and costs for the operator. The advanced toe sleeve with built-in time-delay features maintains the liner integrity throughout the various well operations. The number of available pressure cycles can be predetermined, and the activation of the various cycles can be precisely controlled thereby also controlling when the tool is activated to achieve injectivity. This paper will present the development and field-wide implementation of the ATS technology, which has rapidly gained operator acceptance and resulted in significant time and cost savings.

The Cement Packer approach has been successfully implemented to pursue and monetize minor gas reservoirs of poorer quality. Due to its critical role in power supply to meet the nation's needs, license to operate gas fields oftentimes come with contractual obligations to deliver a certain threshold of gas capacity. The cement packer method is a cheaper alternative to workovers that enables operators to build gas capacity by monetizing minor gas reservoirs at lower cost. Group 1 reservoirs are the shallowest hydrocarbon bearing sand with poorer reservoir quality and relatively thin reservoirs. The behind-casing-opportunities in Minor Group-1 reservoirs previously required a relatively costly pull-tubing rig workover to monetize the reservoir. Opportunities in two wells were optimized from pull –tubing rig workovers to a non-rig program by implementing Cement Packer applications. The tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing. The hardened cement then acted as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized at a lower cost. Tubing and casing integrity tests prior to well entry demonstrated good tubing and casing integrity. This is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement hardened, pressure test from the tubing and from the casing indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool showed fair to good cement above the target perforation depth. These data supported the fact that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to ensure the lowest skin possible. Post perforation, there was a sharp increase in the tubing pressure indicating pressure influx from the reservoir. Despite that, casing pressure remained low, confirming no communication and thus the success of the cement packer.The well was later able to unload naturally due to its high reservoir pressure, confirming the producibility of the reservoirs and unlocking similar opportunities in other wells. Additionally, the cement packer approach delivered tremendous cost savings between $6 – 8 mil per well. Besides confirming the reservoirs' producibility,the success also unlocked additional shallow gas behind casing opportunities in the area.This method will now be the first-choice option to monetize any hydrocarbon resources in reservoirs located above the top packer.

Pressure transient testing has been significantly revamped and various types have been applied for numerous motives over the past decades. In this paper, a methodology and adapted technology have been discussed in detail for enabling downhole testing operations with existing open perforations above the test packer. This methodology enabled successful downhole testing operations where conventional annulus hydraulic pressure pulse system was ruled out for numerous reasons, such as existence of perforated zones above zone of interest and/or well integrity constraints. The proposed method is based on an acoustic, wireless, bi-directional downhole to surface communication telemetry system. The process utilizes acoustic signals to control downhole tools and transmits downhole measurements in real time through a secured network connection. The procedure used in this well testing methodology is proven successful in numerous well test operations for exploration and appraisal wells in Algeria. The continuously unfolding downhole data has enabled end users and stake holders to take actions and decisions that maximized the value gain while optimizing the test durations and drilling rig utilizations. The successful application of this proposed methodology has enabled parameter estimation during the execution phase of the well testing operations. Data measured in real time is coupled with reservoir engineering interpretation to ensure meaningful sub-surface evaluation. Wellbore dynamics and several other inherent noise sources have been successfully identified to avoid snags of misinterpretation. Wells needing stimulation treatment or longer clean-up durations to enhance the well to reservoir communication quality have been handily identified in real time. The methodology has proven hydrocarbon existence in unexplored layers while enabling incorporation of additional test objectives with further assessments of zones of interest. Real time data greatly reduced uncertainties in well behavior and assisted in informed-decision-making process to adapt well test programs in real time. All well testing objectives were achieved by addressing various challenges that are inherent to conventional memory mode downhole testing operations. The methodology presented will enable the downhole testing operations through drill stem testing (DST) in complex wellbore geometries where conventional well testing approaches were rendered unattainable. The proposed solutions will warrant downhole testing of previously un-appraised formation layers that are overlain by perforated producing reservoirs. The methodology is described in detail and systematically so that the procedure and learnings from Algerian hydrocarbon producing basins can be adapted and applied to other well tests elsewhere around the globe.

The fundamental objective of well perforating is to launch an optimum wellbore to reservoir communication. Unfortunately, not all perforating jobs deliver ideal communication quality. In this paper the rudiments of apposite perforating operations, from data integration and job design to safe implementation, are summarized to produce practical guidelines for high productivity perforating jobs. Reviving oil production in mature fields is a major challenge around the globe. In Libya, there are several mature oil and gas fields that requires production enhancement. In some of these fields the challenge was to come up with a methodology that improves the oil production with minimal well intervention while testing the wells in a much quicker way than the conventional wireline conveyed perforating, well kill, swab, and test techniques. Producing zones in Libyan oil fields have lost productivity over the years due to various activities associated with workover operations. Damage was mainly caused by existence of high salinity formation water and unfiltered brine usage to kill or control the wells. Research has proven that wellbore dynamics have a substantial impact on the success of perforating activities during this very high-paced and short-lived event. We have used a technique that combines the static and the dynamic underbalanced perforating techniques to ultimately improve the hydrocarbon production in such mature fields. Advanced downhole gun and charge system designs and downhole tools are combined to enhance oil production. Debris, scale, and crushed rock removal from the perforation tunnels by applying static underbalanced perforating techniques works very successfully in many cases. Numerous field examples and research have also shown that dynamic underbalance can greatly enhance the tunnel clean up and well productivity. In this paper we are showing that combining static and dynamic underbalanced perforating ensures the optimum perforation tunnel structure. We have applied this technique on numerous wells for the purposes of perforating and re-perforating. Several wells were reperforated to improve the well to reservoir communication quality of existing plugged and damaged perforating zones. In most of the cases new perforating intervals were also added based on production logging and reservoir saturation log results. We have gained extraordinary oil production for several wells. This methodology with improved design increased oil production more than 400% in some wells. Results of this study are presented in an easy to follow way to ensure learnings are passed on to the industry for achieving improved results elsewhere. The techniques outlined in this paper will permit enhanced perforation designs via utilizing available software packages in challenging environments where conventional approaches can be inadequate. The methodology described in this paper is unique in terms of combining the existing techniques in an accessible way.

The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased hole gravel packing or frac-packing as the completion of the choice. Despite the reliability of these options, they are more expensive than standalone screen completion. Since several developments are not designed for cased hole gravel pack or frac-pack, purpose-driven sand control methods for cased and perforated wells are recommended. This paper employs a combined physical lab testing and Computational Fluid Dynamics (CFD) for lab scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail. A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the role of perforation density, the fill-up of annular gap between the casing and screen, perforation collapse and screen plugging on pressure drop. The experiments consisted of a series of step rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate in which the sand filled annular gap will fluidize and also sanding would be different for different fluid density. Both test results and CFD simulation scenarios comparatively allow to establish the relation between wellbore pressure drop with screen and perforation parameters and determine the optimized design. The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completion. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy, rather than using gravel packing and frac-packing methods in cased and perforated completions.

This paper describes the design, planning, and successful installation of a fit-for-purpose casing patch to isolate a water producing zone, the subsequent perforation of an adjacent zone, and a gravel pack completion in the same well for the first time worldwide. The proximity of the zones and the sand control requirements made the design and planning of this job a challenging task that is detailed in this manuscript. The main producing zone in the SW-21 well watered out after few years of production. A second target was identified located just four feet below the main zone. To extend the life of the well and to add reserves from the secondary target, the upper 100% water zone had to be isolated. A fit-for-purpose, thin wall casing patch solution was designed to: allow perforation of the secondary target while maintaining patch integrity, allowing for the installation of sand control screens; and resist following gravel pack completion, by keeping the minimum recommended clearance between casing and screens, inside the minimal patch-reduced diameter. The re-completions program consisted of: 1. Successful recovery of existing gravel pack from the main producing zone and thorough wellbore cleanup. 2. Casing patch installation consisting of a 23-ft long patch to isolate the water-producing zone. In this case, a specific engineering design analysis was required to ensure that, because of the very close distances between zones, the patch would still maintain integrity during perforation of the secondary target and the resulting patch overlap. 3. Successful integrity test to confirm upper interval isolation before perforating the lower interval. 4. A precise perforating operation carried out to perforate the secondary zone. Based on engineering recommendations, some length of the installed patch was perforated to guarantee a minimum unperforated distance of casing patch between zones to guarantee patch sealing features. 5. Once perforation was successfully accomplished, a gravel pack completion—inside the casing patch reduced diameter—was executed along the new zone for sand control purposes, and the well was put into production. This paper presents the different interactions between a multidisciplinary research and development team, and completions and reservoir engineers to come up with a full solution for water isolation and sand control under such challenging conditions. For the first time in the world, a casing patch was used to isolate a water zone, and at the same time, perform a gravel pack completion inside the patch reduced diameter. Well performance, without any mechanical issues, confirms the success of the provided solution.

This paper introduces pump-down diagnostics, an economical process in which cement sheath integrity, perforation cluster spacing and frac plug integrity can be assessed for every frac stage, potentially leading to improvements in stimulation, completion, cementing and drilling practices. It is based on analyzing wellbore pressure responses occurring at key segments of the wireline pump-down and perforating operation and correlating the results among multiple frac stages and wells in a field or play. A special requirement is that the frac ball (ball check) is inserted in the frac plug and pumped to seat prior to performing perforating operations. A complementary benefit of this process is that selectively establishing injectivity in the most distant perforation cluster can be used to establish inhibited HCl acid (wireline acid) coverage across all perforation intervals for uniform reduction in near-wellbore tortuosity. Reviews of pump-down diagnostics field cases from several unconventional plays provide the following insights. 1.) pump-down diagnostics are time efficient and economical, requiring about 15 minutes per frac stage, 2.) evaluating communication to the previous frac stage can serve as a key performance indicator for treatment control or cement sheath integrity, 3.) pump-down diagnostic results can be more reliable than cement bond log evaluation, 4.) stage isolation characteristics can be strongly affected by cluster spacing.

Hydraulic fracturing is a widely applied technology to increase recoverable reserves and accelerate production in low permeability reservoirs. In this technique, the hydraulic fractures are generated by pumping a fracturing fluid at a high flow rate and introducing proppant with the fluid to keep the fractures open after the pumping is halted. In horizontal well fracturing, one of the most important factors in this method is the proppant transport and distribution in the wellbore and among perforation clusters. Uneven proppant distribution between multiple clusters/fractures can cause a drop in the near-wellbore fracture conductivity, which in turn causes a negative impact on the production performance of the hydraulic fractures. This paper presents new experimental correlations that were developed and can be utilized to predict the proppant distribution between subsequent perforation clusters. The experimental correlations were developed using dimensional analysis from appropriate experimental data. The experimental data for this study was obtained from a horizontal wellbore apparatus with three perforation clusters at shot densities of 4 SPF with 90-degree phasing. Several experimental tests were conducted on 20/40 and 40/70 for white sand (SG of 2.65) and ultra-light weight ceramic (SG of 2.0) using freshwater fluids at three flow rates and over a wide range of proppant concentrations. Four types of experimental correlations were developed by experimentally investigating the effect of each parameter on the proppant distribution between the three perforation clusters. The first correlation type developed is based on the proppant concentration, while the second type is based on the flow rate and proppant concentration. The third correlation type includes the particle median diameter as another independent variable, along with the flow rate and proppant concentration. The fourth and final correlation developed consists of the proppant density along with the proppant median diameter, flow rate and proppant concentration as its independent variables. This fourth and final correlation was validated by comparing the predicted values to the laboratory values. The results of correlation analysis comparison to lab data show that the 20/40 and 40/70 ULW ceramic showed the lowest average error values at 2.92% and 1.56%, respectively, while the 20/40 and 40/70 white sand transport predictions were reasonable (average error range of 3.67% - 11.67%). The low error values indicate the high reliability of the developed correlations in predicting the proppant distribution between perforation clusters. To the authors’ knowledge, the developed correlations are the first of their kind to be based on experimental data. These correlations can help to determine the optimum flow rate that is required to attain even distribution of the proppant and provide more insight about the anticipated proppant distribution into and out of perforation clusters.

In the ultradeepwater oil and gas market, operators demand reliability and efficiency in all technical disciplines involved during the entire life cycle from exploration through decommissioning stages. In the perforating segment, specifically, recent technological advancements have allowed service companies to increase electric line (e-line) and tubing-conveyed perforating (TCP) gun footage to save rig time. E-line perforating capacity for 7-in. guns has increased from 15 to 41 m/run (49 to 135 ft/run), while the 4 ⅝-in. gun capacity has increased from 20 to 50 m/run (66 to 165 ft/run). This paper discusses how such advancements led to new benchmarks for perforating footage during deployment of a large gun system in Brazilian presalt, changing the perforation technique, and ultimately reducing operational expenses. During perforating, excessive shock loads are applied on the weak point (WP), so the challenge was to develop a perforating system that could increase the effective perforating footage using 7-in. and 4 ⅝-in. guns without damaging the e-line or dropping the guns because of a pull off. A specially designed WP for high dynamic loading, together with a new 2 ¾-in. outer diameter (OD) cable head was developed. Various software simulations were run to analyze the shock-loading effects on the cable and WP during run in hole (RIH), gun detonation, and pulling out of the hole (POOH). This paper presents seven field case studies in which this new technology was applied. High-speed memory recordings of pressure and radial/axial accelerations were used to acquire actual downhole data during the perforating event to compare with simulation results and calibrate the models. The WPs were analyzed to validate the overall response of the new perforating system. The actual surface tension and downhole data, such as pressure and acceleration, matched the simulation results. During the seven field case studies, the new perforating system using e-line deployment helped improve rig-time efficiency, saving more than 130 rig hours compared to performing the operation using the traditional TCP service, representing more than USD 2 million overall savings. The capability of running long sections of large guns is a significant achievement for wireline-deployed perforating services. During the Brazil operation, the increased efficiency resulted in a reduction of 16 hours of completion phase, which equates to a savings of hundreds of thousands of dollars when compared with TCP operations.

This paper presents the evolution of completion sand control designs for the Peng Lai field in Bohai Bay, offshore China. A range of sand control designs from open hole gravel packs to open hole standalone screens to cased hole high rate water packs and cased hole frac-packs have been tried over time. Evaluation of these various designs indicates that single-trip multi-zone cased hole frac-pack designs provide the most effective method for developing the thick, low net-to-gross, unconsolidated sandstone reservoirs in this waterflood field. The paper describes the completion design and evaluation process used in the field and shows how field challenges led to innovative frac-pack downhole equipment designs. This paper highlights completion practices and results from a range of well types used to develop the large Peng Lai field, offshore China. Development challenges and productivity and reliability results for alternative completion designs are discussed on the basis of field performance. The resulting preferred design, consisting of cased hole frac-packs using large-bore and small-bore single-trip multi-zone equipment are then discussed in further detail with emphasis on development of an innovative, fit-for-purpose, small-bore design. The installation challenges, solutions and successes experienced during the design and installation process and the actual performance and benefits of the new system are also discussed in this paper. Over the course of Peng Lai field development, a range of alternative completion sand control designs have been tried and evaluated. Cased hole frac-packs provide the most effective completion method for the thick, low net-to-gross, sandstone reservoirs. To enable effective completions in sidetracked wells, a 7" single-trip multi-zone frac pack tool has been developed. This small-bore system has been used to complete 13 wells with 67 zones in the field to date, saving over 43 rig days and $8MM. This paper presents reliability and productivity comparisons for a range of alternative completion sand control designs in a single, large field environment. A new 7" single-trip, fit-for-purpose design has been developed for the field and successfully implemented in multiple well campaigns. Installation time data and cost savings are provided.

During hydraulic fracturing of low to moderate (0.1 – 50 md) permeability reservoirs using crosslinked gel fluids, the final proppant stage displacement is designed to leave some volume of proppant slurry above the perforated interval. This practice of underflushing is based on a paradigm that considers the overdisplacement of proppant past perforations to be a major risk to well productivity. The theory behind this paradigm is investigated and finds that it relies on several physically unrealistic assumptions. Numerical simulations were performed to understand the impact of a fracture overflush on well productivity. A new methodology was developed for overflushing fractures that enables significant cost/time savings without impacting well productivity. A multi-well field trial in a 2-20 md reservoir was conducted andcompared well performance from overflushed crosslinked gel fractures to underflushed fractures. Some of the trial results have been reported by the authors ( Chaplygin et. al. (2019) ) and are further updated/analyzed in this work. The analysis confirmed that the managed overflush fractures have equivalent performance to underflushed fractures. The analysis also confirmed multiple benefits from the managed overflush wells including reductions in completion costs/time and an improved HSSE risk profile. The results challenge the validity of this decades old paradigm.

The La Cira Infantas field is located in the Middle Magdalena basin in the Santander region of central Colombia. This oil-producing development is under secondary waterflood using five-spot and inverted seven-spot patterns. The reservoir has high vertical and horizontal heterogeneity, and there was concern about effectively draining the reservoir. A new hydraulic fracturing design was deployed for the first time in Colombia (and South America) to improve drainage and surveillance. With over 1200 producers and 500 injectors, the La Cira Infantas waterflood is well established. Waterflood surveillance indicated less-than-optimal recovery due to near-wellbore skin in the injectors and suspected poor height coverage. A novel proppant technology was incorporated into the fracture design allowing for consolidation of the proppant pack in the fracture with low bottomhole temperature and minimal stress on proppant, enabling long-term undamaged injectivity. This technology also incorporates an inert tracer into the proppant grains, which provides propped height determination after the treatment using a neutron log. This multi-faceted proppant technology was successfully deployed on one well, and additional wells are planned in 2020. This paper will first review the background of the field development including current completion techniques, along with the challenges being faced with the waterflood recovery. It will review the self-consolidating proppant technology and show the benefits of its use in this application to promote high-conductivity fractures and minimize damage to injectivity. The companion tracer technology will be presented along with plans to perform neutron logging and identify propped fracture height. This information can be fed into fracture propagation models to determine the fracture geometry, which is then used for reservoir and waterflood surveillance analysis. The technique allows for meeting the goal to improve injectivity into both high-skin and low-permeability reservoirs. Although this proppant technology has been used in other frac pack applications, this is one of the first case histories of the technology being used on land for improving injectivity and waterflood coverage in Colombia. This paper will be useful for reservoir and completion engineers working on waterflood fields that contain vertically and horizontally heterogeneous formations, and wish to maintain undamaged injectivity, improve waterflood sweep efficiency, and monitor the proppant pack over time.

Objective/Scope The main objective is to build on prior publications of decline curve analysis, based on theoretical producing and fluid flow characteristics (Matthews and Lefkowits 1956, Fetkovitch 1975, Cox 1948 ). In this paper, we relate petrophysical predictions of ultimate oil recovery to actual rate-time well performance by adjusting recovery efficiencies and well-bore drainage areas. Method/Procedure/Scope From an analysis of a number of producing wells in the Permian Basin a model (Zimbrick) has been derived for average decline curve performance. This model has been found to work in other basins; however, basin specific models are likely to be required in some situations. This model is then combined with petrophysical estimates of recovery efficiencies to generate rate vs. time decline curves. This is then compared with actual production to determine drainage area. Three basic questions are then addressed: Is the drainage area reasonableš Is the recovery assumption reasonableš Does the petrophysical analysis need adjustmentš Additional adjustments might then be necessary. Results can be interpreted as follows: If the petrophysical analysis suggests the well is under-performing, reservoir quality has degraded within the drainage area. If the petrophysical analysis suggests the well is over-performing, reservoir quality is better than predicted. This could be a consequence of contribution from a fracture system and/or from adjacent reservoirs close to the perforated interval. Results/Objectives/Conclusions Results from the analyses of four oil wells in the Big Horn Basin of Wyoming are presented. All four wells have excellent log suites allowing for reliable petrophysical analysis, are now depleted, and have rate-time data available. The nominal well spacing is for 15-acre drainage. Petrophysical predictions for rate-time performance were run for two basic cases: For only the perforated intervals - often four of five within the gross perforated interval. For the gross perforated interval - petrophysical analyses indicated additional pay that was not perforated. Using a constant recovery efficiency of 20% the drainage areas were adjusted to get an exact match with actual performance. For three of the four wells, adjusted drainage areas are significantly greater than 15 acres. Factors influencing the calculated drainage areas are: There is no well interference and drainage is occurring from adjacent undrilled acreage. Recovery efficiencies are higher than 20% Oil is coming from zones additional to the gross perforated interval, or from a fracture system. Novel/Additive Information The method compares petrophysical estimates of recoverable hydrocarbons with actual rate-time performance, allowing for considerations of drainage areas and recovery efficiencies and the possibility of production coming from a fracture system and/or adjacent unperforated intervals. Estimates can be made from the petrophysical analysis of adjacent undrilled locations of rate-time performance before the well is completed.