Drilling in the Appalachian basin in Pennsylvania has evolved since its inception. Operators have shifted their focus from mere wellbore delivery to delivering wells in the shortest amount of time to reduce risks and costs, as well as drive efficiency. This paper presents a case study in which offline cementing helped improve operation efficiency by reducing drilling times and provided significant cost savings.
Offline cementing is not a new concept. In Q4 2015, an operator drilling in the Eagle Ford shale began the movement of their program toward offline cementing of both the surface and production casings. The operator determined that reducing flat time was crucial to create a cost savings (
The service company was able to cement both the surface and intermediate casing strings offline while the operator skidded to the next well to begin rigging up. All surface casings were drilled and cemented offline and the rig skidded back to drill for the intermediate casings, which were also cemented offline. Approximately 15 hours was saved by skidding between surface strings, and another 16 hours was saved between intermediate casings.
This paper discusses the successful use of offline cementing during drilling operations in northeastern Pennsylvania. The flat time reduction achieved during this drilling program can be quantified into a cost savings of approximately USD 80,000 per well.
Research and development drives success in shale plays throughout the world, enabling operators to deploy new drilling, completions, and production technologies to reach more reservoir area and extend the life of production wells. This work demonstrates the development, validation, and deployment of an extreme torque casing connection addressing technical challenges of tubulars in unconventionals.
Throughout the well lifetime, Oil Country Tubular Goods (OCTG) experience various loads during the installation, stimulation, and production phases. Some of the challenges experienced during the stimulation and production phases relate to internal and external pressure resistance, sealability, corrosion and cracking, erosion, and wear. Furthermore, with the increase in lateral length and the more demanding well geometries, the OCTG capabilities related to high cycle fatigue, connection runability, and torque limits become more important to safely and efficiently reach the total depth of the well and ensure integrity throughout well life. Another scenario in which the torque limit of an OCTG connection is important is rotating while cementing, a practice undertaken to mitigate sustained casing pressure, improve well integrity, and completion efficiency.
We present the key elements in the development of a casing connection that overcomes these challenges and the decision process leading to a prototype. To prove the design concept, a fit-for-purpose testing protocol was adopted to validate its performance, replicating the installation, stimulation, and production phases under the expected loads. Once validated, a pilot involving casing installation, rotation while cementing and stimulation was completed in two wells, and its outcomes will be discussed in this work.
This novel casing extreme torque connection, designed to overcome the application challenges, enables the installation of casing in longer laterals, together with the improvement of well integrity through rotation while cementing.
The performance of the product, tested through a special procedure while ensuring reliability, was confirmed by the case study from the Niobrara shale. A new connection considering the challenges of wells in unconventional plays must account for several aspects from design to installation. We show the process, from the design stage and validation, leading to successful field deployment.
Several aged oil wells in offshore oil field are drilled in a conventional method. These wells are subjected to Casing-Casing Annulus (CCA) problems that might appear during the production operation and/or the shutdown phases. A continuous monitoring is performed to avoid issues related to well integrity and safety. The expected source of Casing-Casing Annulus (CCA) problem is mainly due to poor primarily cementing placement into the outer-casing strings especially across shallow aquifers formations. Due to long shutdown period on subject wells, these wells are encountered with high rate of CCA phenomena among other wells. An immediate mitigation action is required to resolve the issues by applying rig workover operation which is considered highly cost approach with low success rate. The rig workover operation results might lead to suspension or abandonment of these wells. The impact will affect the production target and the oil recovery around the area.
A new methodology approach was selected using chemical sealant recipes as a rigless operation to repair CCA problem with cost-effective and safe manner for first time in offshore filed. Based on the wellhead and annuli survey, the bleed down and build up tests were conducted and followed by close monitoring on suspected wells, which revealed sustained casing pressures and fluid return at the surface. Several fluid samples were collected and analyzed in the lab. Based on the findings, the procedures and the proper design were conducted to inject the chemical sealant into connected cement channels behind casing strings. Curing time and injection rate with required volumes of chemicals were considered based on the pressure responses and chemical performance.
The results from the rigless operation job utilizing the new approach showed wide-ranging success rates based on well by well cases and conditions such as 1) Age of the well, 2) Sustained pressure observed at the surface, 3) Injectivity rates, 4) Chemical additives volume and 5) Downhole conditions (pressure / temperature).
The new technique added a great value on restoring the well integrity and saving the rig operation cost. In addition, the approach contributed to achieve maximum sustainable production target through ensuring the well operability and reducing the production down time. Challenges, methodology, work schedule, risk assessment, lessons learned and findings have been covered in this paper.
Using a single universal spacer surfactant to clean a wide variety of oil-based mud (OBM) is considered the "Holy Grail" of spacer fluid system. Specialty chemical and service companies have devoted intense research and vast resources to develop the ideal spacer surfactant, but their efforts have not led to a singlesurfactant solution due to uniquely different drilling mud properties. It is no surprise to experts in the field that surfactant selection is extremely mud specific. For instance, one surfactant may effectively clean certain types of OBM, but fail in another mud from a different location that has the same density and base fluid. As a result, service companies have numerous surfactants in their portfolios, further complicating logistics and operations. This paper presents the discovery of a high-performance universal biomicromaterial, which can significantly improve the cleaning performance of any surfactants/spacer fluids to remove most, if not, all types of drilling mud. The innovative bio-micromaterial is an eco-friendly byproduct from another industry.
Successful cleaning of the drilling mud was demonstrated by standard rotor testing with different OBM samples from across North America, and the percentage of mud removal was determined. Furthermore, the ability of the innovative micromaterial to efficiently clean the mud was verified by measuring the strength of bonding between the set cement and the metal casing that had been cleaned by the spacer fluid after drilling mud contamination. Basically, this new procedure simulates downhole fluid displacement by the intermediate spacer fluid, which is ahead of the cement slurry, displacing the mud. Stability and mixability were also studied to determine the effect of the bio-micromaterial addition to the spacer fluid. Finally, a fundamental scientific study using thermogravimetric analysis and imaging techniques was done to characterize the material and determine its thermal stability.
For the first time, newly discovered, high-performance, universal cleaning micromaterial is presented to enhance the OBM removal of any spacer fluid design. This groundbreaking research has successfully demonstrated the unconventional advanced material to be a universal cleaning, single-additive spacer admixture for a wide variety of drilling mud from various regions across North America. To our knowledge, based on extensive literature search, this is the first report about the application of this natural waste product in wellbore cleaning fluids like the spacer.
Ghanavati, Mohsen (Global New Petro Tec Corp.) | Volkov, Maxim (TGT Oilfield Services) | Nagimov, Vener (TGT Oilfield Services) | Ali Mohammadi, Hamzeh (University of Calgary, Global New Petro Tec Corp.)
Production casings of Cyclic Steam Stimulation (CCS) or steam-assisted gravity drainage wells are exposed to significant temperature variations which in many cases resulted in casing breaks in the weakest part which are typically connection joints. The paper focuses on the new downhole logging approach, in monitoring and detecting production casing connection breaks through tubing without requirement for tubing retrieval.
The metal well barriers can be assessed by utilizing electromagnetic (EM) pulse defectoscopy. This is done by running multiple coaxial sensors downhole in tandem. Each sensor generates EM pulse and then records EM decay from surrounding metal tubes. Modeling of recorded EM decay enables precise assessment of metal loss or metal gain in up to four concentric barriers. However, the tool had never been used previously to detect minor defect features as casing breaks through the tubing. To identify casing breaks several yard and field tests have been conducted and new methodologies were developed. The last one included the recognition of specific patterns of raw EM responses, analysis of hole sensors and utilization of data from all coaxial sensors utilized during the downhole survey.
The new approach including downhole EM pulse tools and new data analysis have been implemented to detect casing connection breaks in over a hundred Cyclic Steam Stimulation (CCS) and SteamAssisted Gravity Drainage (SAGD) wells. The paper demonstrates the testing of the application feasibility in a comprehensive yard test and extends to real field examples. All detected breaks were confirmed after tubing removal and were successfully repaired. Paper highlights detection challenges due to different casing connection break types: minor breaks, partial breaks (contrary to fully circumferential), and casing breaks aligned with tubing connections. The technology has helped Operators to fulfil the objectives of connection break detection without tubing removal through a non-intrusive, safe, quick and economical approach.
Today, CSS and SAGD Operators should confirm casing integrity repeatedly prior to each subsequent steam cycle through the time and resource consuming approach of tubing removal and checking the casing integrity mechanically. Utilizing through tubing electromagnetic diagnostics, enables Operators to pick up multiple casing connection breaks in a single run without tubing retrieval.
Successfully spotting an Off-Bottom Cement Plug (OBCP) has been problematic in the oilfield for decades. The use of high viscosity support spacers below the cement plug has been an attractive method to support the cement. These isolation spacers have traditionally been formulated with either biopolymers or bentonitic clays, but they too often fail to support the cement plug due to inadequate viscosity or poor placement. The result is that the cement slumps below the desired location in the wellbore, requiring some remedial action such as spotting an additional spacer and OBCP. One response to this challenge has been the use of a packer to support the plug, but this entails the additional cost of the packer plus the rig time required to place it. A better method was needed to increase OBCP success while reducing costs. A new isolation spacer technology was adapted to meet this challenge, and the resulting field applications are described in this paper. Developmental lab testing will be detailed along with an initial trial well where the spacer was used to isolate a retrievable packer from workover debris. After success there, the same spacer technology was used to successfully support an OBCP on a rigless well abandonment.
A key to achieving zonal isolation is the complete removal of drilling mud from the annular space between casing and formation and the replacement of the mud by an appropriately designed cement slurry. Although fluid displacement simulators have been available in the industry since the 1990s, a new-generation mud removal simulator has been introduced that provides new levels of details and accuracy. The simulator can be used for all types of wells, but it especially brings value to complex wells such as those found in deepwater Gulf of Mexico.
The new fluid displacement simulator comprises a stiff-string centralization model that accurately predicts the casing standoff in a 3D wellbore. It accounts for fluid mixing inside the drillpipe and casing while the fluid travels down the wellbore and includes a high-resolution annular displacement simulator that accounts for the 3D wellbore shape and solves for azimuthal and axial flows. Thanks to these three new features, the simulator generates highly accurate and reliable results with which the cement job design can be optimized, leading to a higher probability of meeting job objectives and achieving zonal isolation.
The new generation simulator was used to design and optimize cement jobs in the Gulf of Mexico with strict cement job objectives. The results of the simulator were compared to actual results of post-job wireline cement evaluations logs. The paper includes several case studies of deepwater and shallow water cement jobs in various complex wellbore configurations. Actual cement job data were used to rerun the simulator, and the results were compared with both the prejob cement design and the post-job evaluation logs. The comparison shows that the wireline evaluation results match the fluid displacement simulations very closely when using the stiff-string centralization model in combination with the new fluid displacement simulator, therefore confirming the accuracy of the model.
Using the new stiff-string casing centralization and 3D fluid displacement simulator throughout the early planning and design of the cement job allows for an improved cement job design. The simulations highlight possible challenges early in the planning of the cement job so that any required changes or contingencies can be prepared ahead of time, thus resulting in a cement job design that meets the planned objectives.
Nafikova, Svetlana (Schlumberger) | Bugrayev, Amanmmamet (Schlumberger) | Taoutaou, Salim (Schlumberger) | Baygeldiyev, Gaygysyz (Schlumberger) | Akhmetzianov, Ilshat (Schlumberger) | Gurbanov, Guvanch (Schlumberger) | Eliwa, Ihab (Dragon Oil)
A major operator on the Caspian Turkmen shelf has started to encounter sustained casing pressures (SCP) attributable to insufficient isolation across a hydrocarbon gas zone, due to downhole stresses and other contributing factors. Enhanced placement techniques of conventional cements failed to prevent SCP, confirming the requirement for an alternative cement system that can withstand anticipated stresses and resolve this challenge. An innovative and cost-effective solution was applied and successfully solved the SCP challenge due to its unique self-healing properties.
If cracks or microannuli occur and hydrocarbons reach the cement, the system has the capability to repair itself, restoring integrity of the cement sheath without external intervention. The cement system is placed conventionally in the annulus across or above the hydrocarbon-bearing formation. It then acts as a pressure seal, expanding to accommodate downhole changes and healing if any hydrocarbon reaches it. This technology has been used in four wells in the field with excellent results.
Two wells were used to demonstrate the capabilities of the self-healing cement as a lead cement slurry, which created a cap over the pay zones. The self-healing cement was designed with low Young's modulus for optimum flexibility. To minimize the risk of set cement integrity failure due to microannuli or microdebonding from chemical shrinkage after setting, linear expansion up to 1.2% was incorporated into the design. After cementing, the wells were intentionally exposed to a sequence of high-pressure tests, which induced annular pressures in the wells. However, because of the self-repair capability of this cement, isolation and integrity were effectively restored in the two wells within 1 to 2 weeks without external intervention. As a result, the self-healing cement technology has become the standard for the field for all future wells, and the operator plans to extend the self-healing cement technology to other fields with similar challenges.
This paper clearly demonstrates successful casing pressure remediation without intervention by engineering a flexible, self-healing cement system. The design strategy, execution, evaluation, and results for two wells are discussed in detail and will help to guide future engineering and operations around the world.
Dooply, Mohammed (Schlumberger) | Schupbach, Michael (Murphy Exploration & Production Co.) | Hampshire, Kenneth (Murphy Exploration & Production Co.) | Contreras, Jose (Schlumberger) | Flamant, Nicolas (Schlumberger)
Two of the most important parameters to monitor during a primary cementing job are the pumped-in and return flow rate measurements. To achieve optimum quality control of a primary cementing job, measuring annular return rates and comparing them with simulated data in real-time will provide better understanding of job signatures and result in the best possible top-of-cement estimation prior to running any cement evaluation log or taking decision to continue drilling the next section of the well. The return rate job signature along with the wellhead pressure is essential to understand the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical. Historically, cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flow meter installed on the annulus return line, and a simple verification of mud tanks volumes versus pumped volume, as reported by drillers or mud loggers, more than often resulted in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in & flow rate out). This paper will review a solution developed to mitigate the lack of a direct flow rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.
Offshore field started on operation to produce crude oil with 27 API° as sweet crude and sour crude with 32 API° since 1960. Large number of wells in offshore field revealed undesirable phenomena related to well integrity issues as potentially sustained pressure on several casing strings. Well integrity management emphasis on preventing well problems related to well safety and integrity such as casing leak, Sustained Casing Pressure (SCP), downhole safety valve (DHSV) failures. The direct impact from integrity management added great value in terms of decreasing in operating down time, improvement in well control and safety aspects, and reducing unplanned repair intervention. In addition, the loss of well integrity can cause major accidents with a severe risk to the personnel, asset and environment.
The paper aims to illustrate a methodology results on applying effective well integrity monitoring techniques. A focus was made to improve monitoring well integrity through reviewing wellhead surface parameters, annulus sections pressure and downhole condition. In addition, the subject wells should be kept under close monitoring at a safe operable with an integral condition. Non-integral wells are common in aged wells, which are becoming a challenging issue to restore its integrity and operability especially for such aged completion. As a part of well integrity review, the concerns had been identified, investigated, and subsequently mitigations actions are recommended to restore the well integrity. Currently, it is confirmed that 25 oil producers with casing leak problems, which resulted to be converted from conventional completion to a slim hole with limited future accessblity. Based on lab reusltes and logging interpretations, it is indicated that the root cause of casing leaks is due to corrosive water flow from shallow aquifer formation. Therefore, an immediate remedial action is required to improve well construction.
A successful worked over well with integrity issue as a casing leak was repaired by cement squeeze into across the corroded casing interval, which enhanced well integrity and restore well productivity. The resulted showed that tubing leaks encountered with well integrity due to sustained casing pressure. Therefore, the pressure on production casing can cause severe failure with catastrophic damage. The results also illustrated that a water flow through poor cement is a major cause of sustained casing pressure in the outer casing strings. The cause of pressure on production casing is generally easier to diagnose than that pressure on one of the outer casing strings. Challenges, methodology, work schedule, risk assessment, lesson learned and findings are included in this paper. The effective well integrity management resulted on great deal of benefits, which are related to securing wells, well operability, cost saving, and sustained maximum production target.