Vera, Vanessa (Halliburton) | Torres, Carlos A. (Halliburton) | Delgado, Eduardo (Halliburton) | Pacheco, Carlos (Halliburton) | Sampayo, David (Halliburton) | Higuera, Josue (Equion Energia Limited) | Torres, Monica (Equion Energia Limited)
Underbalanced perforating with conventional cable operations involves several risks associated with well tortuosity, cable tension capacity, gun lifting, and the capability of achieving the optimum underbalance for effective tunnel cleanup (
CT-conveyed perforating is ideal for this type of wellbore. To achieve the proper underbalance and depth correlation to perforate the target interval, an RTFO CT system provides the most accurate and reliable depth correlation process, in addition to real-time pressure and temperature monitoring inside the CT and the outer annulus.
Using the RTFO CT system, only two runs were necessary to complete the perforating program, in accordance with the operator design, rather than performing an additional run needed for pickling and to generate underbalanced conditions.
The use of the RTFO CT system can help to prevent correlation errors resulting from CT elongation.
A CT structure was not necessary to deploy the guns based on the finite model analysis that calculates maximum stress and flange bending, including a safety factor.
A hydraulic firing head can be used with an RTFO CT system to activate the guns without affecting the integrity of the fiber optics or the downhole sensor tool after detonation.
The RTFO CT system enabled the operator to evaluate the reservoir potential. The evaluation results indicated that one of the zones is a low producer, which avoided the pumping of unnecessary nitrogen to induce the specific zone.
The use of a downhole pressure sensor enabled the identification of the time at which the guns were detonated.
Improvement to the rigup was evidenced and enabled time optimization without affecting the operation.
The casing collar locator (CCL), used for depth correlation, was a crucial factor in reducing operational costs because it helped to optimize placement accuracy and gun detonation and to prevent misfiring (
A successful perforating operation was completed with 4,000 psi underbalance in a new formation using hydraulic detonation with continuous real-time downhole condition monitoring before and after detonation, enabling the operating company to make decisions in real time.
This new approach of using an RTFO CT system combined with the hydraulic firing head can be used to perforate new formations in these crucial scenarios (wells with production greater than 20 MMscf/D and zones with continued sand production).
An IOC in Bolivia evaluated the possibility of hanging velocity strings (VS) in five large liquid-loading wells in a mature field that were either partially flowing with slugs or completely closed. With less flow area, the gas flow velocity should increase—helping improve recovery capacity, water, and condensate—to prevent liquid-loading effects, thus extending the life of well.
VS are used with an average length of 5000 m of 2.875-in. coiled tubing (CT) and were installed in the hanger on top of a Christmas tree valve. The well flows through the annular space between the CT production tubing path or the CT internal path, and the CT VS needed to be capable of gas lift injection by the CT path and annular path. The operator preferred to run in hole (RIH) the CT without pumping any fluid to help prevent damaging the formation. When the VS were recovered from the well, the VS bottomhole assembly (BHA) should have had a mechanism/device that permitted pulling out of the hole (POOH) without pumping any fluid inside the well while maintaining well-controlled pressure.
The campaign consisted of five wells that produced CO2 (3 to 4%), water, condensate, and gas. These wells are located in a remote mountain area with limited roads to transit the large loads.
The work involved using a 2.875-in. CT 16 chrome (Cr) run in two stages. In addition to the dimple connectors, landing nipple, and pump-out plugs (POP), a customized BHA was designed for the operation. With reference to the CT's combined stress factor, the lower 2900-m piece was either RIH partially filled with water or empty. Dimple connectors were installed, the upper string was RIH, the CT was installed on the CT hanger spool, and a nitrogen membrane generator was used to unload the fluid.
Significant cost savings, approximately USD 1.5 million per well, were achieved using CT equipment and chrome string compared to the cost of workover equipment and running jointed chrome pipe. After the installation of the first VS, the well experienced increased production of 40% to 3.5 MMscf/D and a decreased bottomhole flowing pressure of 500 psi. Stable well flow extends the life of the well. A second well that was closed in after VS installation exhibited an increased production from 0 to 1.5 MMscf/D. During the writing of this paper, an additional three wells will be completed using these methods.
This paper discusses the engineering design, tension, pressure testing of tools for the VS BHA, joint BHA testing, CT connector customized design, slip ram blowout preventers (BOPs), CT hanger, etc. Operational procedures presented discuss joining a two-piece VS and a 2.875-in. chrome CT with results and lessons learned highlighted.
In North America, refracturing has been found to be effective in many instances for increasing the longevity of the well production and helping to drill and complete offset wells. Several instances suggest that refracturing by bull-heading is relatively ineffective because fluids and proppants are lost in the pre-existing hydraulic fractures. Refracturing through coiled tubing (CT) provides a large benefit in giving ability to pinpoint the location of the refracturing treatment by creating new perforations using abrasive jetting and using diversion pills for isolating high-permeability clusters. This paper helps elucidate the benefits and production gain when using CT for refracturing jobs.
A case study from the Eagle Ford shale illustrates the impact of CT refracturing applications. When CT was hydraulic fracturing was applied in the first generation of wells with 18 stages, 36% extra production was observed in the first year as compared to the bullheading technique. Simulations based on integrated reservoir and geomechanical earth models, complex hydraulic fracture models, diversion simulation, numerical production simulation and finite element computations enable characterizing the productivity from the CT refrac operations. A comparison is made between the bullheading technique and CT based refracturing jobs. The impact of refracturing using CT on the offset child wells to be drilled and completed is also studied.
The study demonstrates that it is critical to place the perforation locations in areas of undepleted reservoir for successful refracturing. Reservoir simulation results in combination with measurements of fluid flow profile in the wellbore can be used to place new perforations in the right sections. Using the diversion pill was found to be greatly effective in improving the fracturing fluid diversion and stimulating the undrained reservoir. With the refracturing using CT, the child wells show improvement in productivity along with the parent well. Overall, the parent and child well combination shows 23% increase in production after one year of refracturing when compared to no refracturing in the parent wellbore.
The new approach is verified through the application of simulation and modeling to prove the benefit of CT refracturing operations in unconventional reservoirs. By adopting the key learnings and approach followed in this paper, operators can maximize their chances to improve productivity and compare various refracturing scenarios.
A new high-strength electrical release device has been developed that supersedes the typical weakpoint and achieves the same strength as the tool tension rating. A stronger release device facilitates running heavier tools on wireline, along with the ability to run significantly longer gun strings, which increases operational efficiency. The release device was subjected to a rigorous qualification program conducted to ensure the highest safety and reliability of this device under demanding conditions.
This technology uses a motorized release that holds two sections together via retractable dogs. The release device operates using new telemetry protocols that are combinable and segregated from other communication schemes. An optional battery with a preset timer provides redundant control if electrical communication is lost during operations.
After the electrical release signal is sent, the motor activates the release mechanism, enabling the device to separate, even with significant residual tension on the toolstring. Completion of rigorous qualification testing was necessary to confirm performance for the heavy load requirements and high shock levels characteristic of long perforating toolstrings.
The new electrical release device has delivered flawless performance in seemingly impossible well programs. In field cases, the device was the optimal answer in providing a secondary release device that is high functioning in the harsh perforating environment. One case presents the completion of a project that involved the collaboration of six product lines. The release device was used with coiled tubing deployment of extremely long gun strings in a reservoir containing high H2S and CO2 content. The device enabled a significant reduction in the number of coiled tubing runs, which resulted in a significant increase in operational efficiency. Another application enabled the conveyance of large gun strings using wireline, which reduced the number of descents required and saved valuable time for the operator. These well programs were successfully completed because of the extreme engineering qualification achieved. For example, surface integration testing involved a maximum allowable gun string of more than 120 ft in a well to model downhole exposure. If this trend continues, it is possible that this device will change the future of wireline perforating operations.
The new controllable electrical release device with exceptional strength enables the deployment of heavy tools and long guns on both coiled tubing and wireline. This will lead to efficiencies in well design as well as optimization and a higher standard in wireline perforating operations.
The coiled tubing (CT) industry continues to operate in deeper and higher pressure wells and in more challenging environments, thereby extending the operating envelope for the service worldwide. CT operations for cement milling provides a safer, faster, and more economical solution, but achieving the desired results in a high pressure, high temperature (HPHT) offshore environment using corrosive brine as the milling fluid is challenging.
This paper describes various challenges and customized remedies for a cement milling operation in an HPHT well with high-density brine, which made milling challenging because of limitations on pumping rates, low viscosity, and fluid corrosiveness.
This offshore gas well had a bottomhole static temperature (BHST) of 400 °F and reservoir pressure of 12,000 psi, with a completion of 9-5/8 in. casing from the surface and a 3-1/2-in. liner hanging from 4,606 meter measured depth (mMD). A 1.75-in. outer diameter (OD) CT string was used to accommodate the internal diameter (ID) restriction of the liner. The allowable pumping rate in the 1.75-in. CT was restricted as a result of pipe friction and low viscosity of milling fluid; however, higher annular velocities were needed to lift the cuttings from the wellbore. To overcome this, additional pumping was performed from the annulus of the 9-5/8-in. section. A positive-displacement, metal-on-metal motor was selected over various types of motors. This paper provides details about best practices, including the selection of brine-compatible elastomeric seals, severe corrosion observed on the motorhead assembly (MHA), and redressing of MHA after each run. It also includes details about laboratory tests performed to identify a suitable viscosifier and corrosion inhibitor, as well as the optimum rate of penetration (ROP) and weight on bit (WOB) to avoid large cuttings, surface-fluid handling, and filtering arrangements.
Based on precise tool selection, including power section, bearing section, and corrosive-brine-compatible motor seals, as well as design parameters, such as ROP, annular fluid velocity, particle size, and equivalent circulating density (ECD) under the operating envelope, cement milling of 217 m of cement was completed successfully in an overbalanced condition with no health, safety, and environment (HSE) related issues. Selecting the correct milling motor and mill plays a crucial role in any milling job. Several operational challenges, such as excessive corrosion at a minimum MHA ID, pitting on bottomhole assembly (BHA) components and erosion on ball seats, erosion, and degradation of elastomeric seals at a BHST of 400 °F, were observed. These adverse effects were avoided with engineering controls.
The methods used, tool selection, and customized design helped the operator to find a solution for milling a cement plug in an HPHT well with zinc bromide (ZnBr2) brine, which resulted in reduced rig time and avoided the side tracking of the well. The lessons learned, methods, and best practices described in this paper can be used in a similar application worldwide, which can help to minimize issues related to service quality and HSE.
Correa, P. (Baker Hughes, a GE Company) | Parra, D. (Baker Hughes, a GE Company) | Craig, S. (Baker Hughes, a GE Company) | Livescu, S. (Baker Hughes, a GE Company) | Yeginbayev, A. (Baker Hughes, a GE Company) | Nadirov, Z. (Baker Hughes, a GE Company)
A new horizontal well in Asia was not capable of unassisted flow due to low gas production rates and a wellhead pressure below that required to enter the production gathering system. Two zones were identified at the heel that could increase the gas/oil ratio (GOR). Because these two zones had deviations greater than 80 degrees, coiled tubing (CT) was selected for the perforation and stimulation intervention. In addition, mechanical isolation was required to ensure the stimulation fluids entered only the new zones. Accurate depth control was required for three runs: setting two composite bridge plugs (CBPs); deploying CT-conveyed perforating (TCP) guns for opening two intervals; and milling out the two CBPs without taking returns to surface. All these runs were performed with a 2.875-in. tube wire-enabled CT telemetry (CTT) system. For the first time, a tension, compression and torque (TCT) subassembly was used to improve the milling operation.
The CTT system consists of a customized bottomhole assembly (BHA) that instantaneously transmits internal (i.e., inside the BHA) and external (i.e., outside the BHA) pressure and temperature, and casing collar locator (CCL) data to surface through a non-intrusive tube wire installed inside the CT. Monitoring the BHA force and torque data in real time helped improve the motor and mill performance and life because the weight on bit (WOB) could be adjusted to the recommended values. For instance, based on the optimum working ranges for the motor used, the operator decided how and when to modify the working variables to achieve a reliable and efficient milling process.
The CTT system alone helped set the first CBP at 5363 m measured depth (MD), set the second CBP at 5281 m MD, and perforate the intervals between 5297 and 5306 m MD and between 5152 and 5164 m MD. In addition, the CTT system with the TCT subassembly was used to mill the two CBPs in shut-in conditions, without any stalls. This created a continuous milling operation, reducing the job time and the working fluid volume compared to similar milling jobs using CTT system alone. Comparing this CBP milling job performance with a previous operation in another well with similar conditions (depth, deviation, etc.) using the CTT system alone reduced the milling time for one CBP by 22%. Although the overall job performance exceeded the operator’s expectations, the working parameters used during the CTT system with the TCT sub-assembly job were not constant, leaving a few areas of improvement for the upcoming milling operations. For instance, the constant differential pressure and WOB were not used on every milling pass down.
The novelty of using the CTT system and TCT subassembly consists of real-time monitoring of BHA data for positioning two CBPs and opening new intervals exactly at the required depths. In addition, this approach enables removal of two CBPs by adjusting the milling parameters to achieve the optimum working parameters for the motor and mill, providing direct and positive financial impact for the operator.
This paper describes a recent Directional Coiled Tubing Drilling (DCTD) job that was completed for an independent operator in the Appalachian Basin. The objective was to access target zones identified adjacent to a recently drilled, vertical well using a lateral sidetrack. The target thickness was around 15ft so accurate depth control was critical. It was also considered essential that the entire reservoir section be drilled underbalanced to minimise formation damage.
The challenge was to deliver a productive horizontal sidetrack in an effective and cost-efficient manner. The field development strategy required costs to be kept to a minimum, but the use of high-tech equipment was essential to delivering the production improvements. A 3.2 inch DCTD Bottom Hole Assembly (BHA) and a specialised DCTD engineering software package were enabling technologies. A multi-disciplinary approach was adopted to plan and execute the sidetrack. This approach required inputs to the planning process from all stages in delivering the well, which included: 3D seismic, well trajectory planning, drilling engineering, completions.
This project was ultimately successful in that a dry hole was re-entered and sidetracked to create a productive well, thereby validating the technology and multi-disciplinary approach of the team. The lessons learned from this operation can be used to optimise the planning of future wells and maximise the value of re-entering marginal wells and fields.
This paper investigates the fatigue behavior of Concentric Coiled Tubing (CCT) and specifically the influence of internal and annular pressures on fatigue life and diametral growth rate. This behavior is assessed relative to that of conventional Coiled Tubing (CT) using samples of identical material, with software modelling predictions providing an additional basis for comparison. Samples of 1.25" CT were situated concentrically within samples of 2.375" CT, and both were repeatedly bent and straightened on a standard CT fatigue testing system, with separate pressures in the inner volume and the annular volume between the CT samples. Current SPE literature does not include prior art for any type of concentric coiled tubing fatigue testing or analysis. The testing apparatus used in this study is the industry standard for the assessment of conventional coiled tubing, however this paper presents the world-first experimental study of concentric coiled tubing fatigue.
Since the testing focused on the failure of the smaller diameter samples, baseline fatigue tests were only conducted on the smaller, inner coiled tubing samples. These results are cross referenced to current fatigue models. Concentric samples were tested on the same machine and setup parameters, using special fixturing that allowed the internal sample to move axially on one end, with its pressure contained. A matrix of pressure differentials was examined, with various levels of inner and annular pressures. The exterior pressure was atmospheric for all tests. The orientation of the longitudinal Electric Resistance Welding (ERW) seams in both samples was examined in this study.
The current approach to monitor CCT fatigue integrity is to use a conventional CT fatigue model, based on the differential pressures caused by the inner CT pressure, annular CCT pressure, and well pressure. While pressure may be monitored accurately, uncertainties exist with regards to the influence of radial stress in the tube wall and factors such as mechanical abrasion between the inner and outer coiled tubing strings, especially due to the presence of internal longitudinal ERW seams. Current models assume perfect concentricity; however, eccentricity varies throughout the string in real-world applications. Results from this study include an empirical derating factor, post mortem failure analysis (including assessment of the influence of ERW seam abrasion), diametral growth analysis, and recommendations for future testing.
This paper is a case study of a successful, complex, high-pressure, and heavy-duty fishing job on a live sour gas well in Saudi Arabia. The multidisciplinary effort involved braided line, various sizes of slick line and coiled tubing (CT) intervention.
The paper examines details of the job planning and design as well as the job execution. The well control philosophy and compliance to some of the highest operational standards in the industry will be discussed along with the associated risk and mitigation strategy. This multifaceted job involved fishing a live perforating gun and plug assembly, which was stuck in the liner following a misfire while attempting to set the plug. The fishing job was further complicated due to the presence of a parted section of electric line on top of the original fish.
Recent developments in heavy-duty fishing operations were incorporated into the intervention process. Equally important is the integrated approach used for this complex fishing job with special safety procedures put in place for the use of multilevel scaffolding, multiple cranes, lifting plans, wire and live gun retrieval procedures, contingency plans and multipurpose pressure control equipment (PCE).
Lessons learned will also be presented in the paper. This successful heavy-duty fishing operation has helped push the boundaries of rigless well intervention, improved operational efficiency and opened up additional opportunities for this technology that previously required the deployment of a workover rig or snubbing unit.
Many of the high-impact operational and safety incidents in wireline operations are the direct result of incorrect selection or inappropriate operation of surface equipment. Examples of such incidents are pulling tensions on the rig-up equipment components above their safe working loads and using winch units incapable of pulling the tensions required to retrieve heavy tool strings in deep or tortuous wells.
Current processes and simulation software used to plan wireline operations are focused on the risks and conditions in which the downhole tools and wireline cables selected will operate; they do not include specific assessments of the adequacy of the surface equipment selected and their associated operating practices.
In this paper, we show the outcome of implementing a set of surface equipment assessments in a popular wireline forces modeling software suite. The surface equipment covered in this initial implementation include the wireline cable, hoist (winch) unit, wireline drum, chains/slings, sheave wheels, load cells, powered capstans, and rig anchoring points. We also demonstrate the merits of the quantification of the selected hoist unit horse power and torque versus the tension and speed profiles simulated at all depths for the free and stuck tool conditions.
The use of processes and forces modeling software, including suitability assessments of the surface equipment and operational choices, is particularly relevant to long and/or tortuous wells. Selection of marginal surface equipment in these types of wells can impose severe operational limitations not identified during the job planning phase and create hazardous conditions that can result in safety incidents and large financial losses.