SPE Middle East Oil & Gas Show and Conference

Radial jet drilling, RJD is an unconventional drilling technique that uses the jet energy of high velocity fluids to drill laterals with different geometries in both conventional and unconventional reservoirs. Many case studies are available worldwide have proven RJD as a viable alternative to traditional stimulation techniques, especially in marginal fields. RJD has a lot of application in the oil and gas industry. It is a cost effective completion technique to reach the untapped sweet spots, by-pass damaged zones near wellbore, re-complete old wells, etc.

The present paper outlines the basics of newly developed radial jet drilling technology. Advances in technologies, developments, forces imposed, jet fluid hydraulics, procedures, applications, and challenges of RJD are reviewed in this paper. Simulation studies and several worldwide case studies are discussed to evaluate the RJD technology.

Innovative Surface Jet Pump (Velocity Spool^TM) technology combined with novel compact separation was tested at a remote onshore wellhead location to see if it could increase multi-phase production from low pressure oil wells that were already producing and revive wells that were backed out/not flowing. The technology was mounted on the surface, not downhole and avoided well intervention,

The Surface Jet Pump (SJP) is a passive device which utilises often wasted fluid energy (via choke) from a high pressure (HP) well to reduce the back-pressure of a low pressure (LP) well and boost its’ flow to the production manifold. In multi-phase oil applications where there can be significant amount of gas present, a compact in-line separator (called I-Sep) is installed upstream of the SJP to bulk separate the gas and liquid fluids and allow the liquid motive fluid to be directed to the SJP.

For this trial, one of Caltec's patented SJP multiphase skids was installed at an onshore wellhead location and connected to existing HP and LP wells. Production from both wells was diverted to the SJP to test its effectiveness. The trial tests lasted 3 months.

Results from the first set of tests showed that the SJP boosted production from a multiphase LP well that was already flowing by an additional average of 380 bbls/d with a corresponding wellhead pressure reduction of 45 psi. Results from the second set of tests showed that the SJP revived a dead well that had not been flowing since 2004 and made it flow at an average rate of 1092 bbl/d with a backpressure pressure reduction ranging from 54 to 27 psi. Prior to the trial, several attempts had been made to bring this dead well back into production using other methods but these were not successful. The results showed conclusively that the SJP was very effective in boosting production from LP oil wells. The production gain was achieved by lowering the FHWP of the well and the amount of gain was dependent on the productivity index of the well.

The advantages that the SJP offers over any conventional technologies such as Multi-phase pumps and ESPs are several: it is tolerant to variations in flow conditions, gas volume fractions (GVF) and associated slugging (without affecting performance), it is surface mounted (so well intervention is not required), low cost, easy to deploy, has no moving parts, consumes zero fuel gas/electrical power and uses already available surplus energy.

This paper reports the trial results and discusses the use of Surface Jet Pumps as an alternative to other boosting methods for oil production. The design and operational criteria of the SJP are also highlighted.

The objective of this paper is to demonstrate the design ingenuity and methodology used to complete a unique HIPS system, which was approved and chosen over the conventional and expensive Full Flare System solution for offshore unmanned high pressure gas production facilities.

Some special design features were implemented to fulfill the Safety Integrity Level (SIL-3) requirements and ensure high level of protection for personnel and facilities. Additionally, this paper will illustrate the challenges for facility operators to preserve the HIPS integrity level throughout the lifetime of the facilities.

Demand for inflow control devices (ICDs) in injection applications is increasing, leading to design initiatives by operators and service companies. These initiatives address the more rigorous conditions of injection applications including acidizing, SAGD, and cyclic steam stimulation. This paper will demonstrate the success of an iterative design and qualification process to develop a robust tortuous path ICD that can withstand higher pressures and higher stimulation rates operators desire for injection applications.

The design process started with computation fluid dynamics (CFD) modeling to predict the stimulation flow performance and resulting pressure gradient underneath the ICD's outer housing. This information was input to the finite element analysis (FEA) model to determine the stress and deformation of the housing. Results of a dynamic flow test with strain gages attached to the housing were compared to the simulated deflection. Additional iterations of the FEA model resulted in the final ICD design. An endurance test verified the final design could withstand full length stimulation operations.

The implementation of the design and qualification method enabled the ICD to withstand higher injection rates without losing any ICD functionality. Overall, the maximum allowable injection rate was increased by 50% compared to the proven ICD design used in production wells.

Previous ICD qualification testing mainly involved characterizing the ICD in production, not the rigorous conditions during stimulation. Thus, designs were not subjected to such intensive mechanical integrity testing. However, in carbonate reservoirs it is often imperative to stimulate wells to bypass damage induced during the drilling and completion phases [Bachar, November 2014]. As stimulation techniques for horizontal wells continue to improve, it is important for well completion technology to keep pace. Differential improvements in ICD design enable a much wider range of well stimulation capabilities increasing well productivity over the life of the well.

Underbalance perforation is one of the best practices to insure less damage to the perforation tunnels. Many papers described the effect of the underbalance perforation either static or dynamic on the cleanup of the perforation tunnel based on the King et al correlation presented in (1986). A complete understanding of the effect of both magnitude and duration of the underbalance during the perforation will help petroleum engineers to design a perforation job and achieve the maximum benefit of the perforation in connecting the well bore to the reservoir. A new approach to control not only the amount of the underbalance, but also the duration of this underbalance, has been applied in one of North Kuwait sandstone reservoirs. The results showed the duration of the underbalance during perforation has a significant effect on clean up the perforation tunnel.

Reduction and elimination of the perforating damage (perforating skin) ensures increased well productivity. Previously, the basic technique to clean perforation tunnels in order to decrease perforating damage was static underbalance. The static underbalance has been upgraded to dynamic using a down-hole production valve. The down-hole pressure data was collected by a fast reading down hole pressure sensor with 120,000 reading per second, capable of responding and recording virtual instantaneous pressure changes in the wellbore. A combination between dynamic and static underbalance has been configured to maximize the near well bore clean up around the perforation tunnel. A compressed gas, a packer setting depth and surface release valve were configured to control the duration of the static underbalance.

The results show a 50% improvement in well productivity compared with the other wells completed in the same layers. The technique provided optimum volume and duration of the underbalance for all layers with up to 500 psi difference in reservoir pressures. Since this technique was being used for the first time in this reservoir, several perforating simulations were run and evaluated to select the optimum scenario for this well. A deep perforation charge has been loaded in the optimum gun size to maximize the amount of the dynamic underbalance.

This paper will present the new technique of underbalance to give a clean perforation tunnel and evaluation of the impact compared to the conventional perforation techniques through pressure data and well modeling.

Low-permeability sandstone formations in deviated exploration wells were drilled and completed in 2013 in northeast Thailand. Reservoir simulation modeling indicated that a well would not produce as a result of the tight formation. Hydraulic fracturing was then considered, and a plan was adopted to use this method to improve the well's production using reservoir simulations. Microseismic fracture monitoring was implemented to correlate data with actual fracture propagation to understand the formation's geomechanics.

The fracture design methods were combined with completion and cleanout strategies to help improve well performance. The fracturing design was incorporated into a complete operational procedure, along with contingency plans, a decision tree, and an integrated communication plan, to allow for possible contingencies. Careful planning, fluid testing, and a fit-for-purpose completion design resulted in a successful hydraulic fracturing operation. The microseismic equipment was installed and monitored during the fracturing operation to provide actual fracturing propagation noise signals.

This paper presents the well fracturing technology, operational procedures, and microseismic technology used to better understand reservoir behavior and geomechanics characteristics. The geophone installation and surrounding control on location provided minimum noise interference for more accurate actual fracture propagation data. The computer program then forecasted fracture propagation. Comparisons between actual fracture propagation and the simulated fracture design allowed the operator to better understand subsurface parameters and characteristics for building the reservoir database. The operator was also able to forecast fracturing dimensions to help prevent water production zones. This significant reservoir information can be used for field development to maximize hydrocarbon production.

Fracturing technology and seismic technology were combined to improve the probability of successful hydrocarbon production. Microseismic results demonstrated the actual fracturing plane dimensions and dynamic fracture propagation, and the fracturing computer program provided fracture simulation dimensions and direction. Combining these technologies allowed the operator to obtain more reservoir data for future field development.

Electric submersible pumps (ESPs) are a widely used artificial lift technology. Conventional ESP systems provide power with a cable banded to the outside of the tubing. These systems have drawbacks in terms of installation speed and efficiency. To overcome these obstacles, a novel cabledeployed (CD) ESP system developed for use in a high hydrogen sulfide (H₂S) production environment is a future solution. This paper focuses on the challenges, results, and lessons learned from the first field deployment in the world of a rigless high H₂S, CDESP system.

A metal jacketed power cable was a key enabler to the CDESP system. The metal jacketed power cable delivers the best protection for a H₂S attack and provides a smooth outside diameter that could be gripped on and sealed. The cable had been tested to withstand H₂S levels up to 15% and chloride levels in excess of 150,000 ppm with an expected service life in excess of 10 years.

To overcome well control concerns, a vertical cable hanger spool (VCHS) was developed enabling the ESP cable to be terminated below the master valve. In addition to the surface termination of the cable, the VCHS provided hang off and production flow through capabilities.

The CDESP system, using a specialized inverted ESP, required close integration between several equipment and service providers during the development of equipment and procedures to ensure success in the installation of the system. The system's initial deployment was in a benign onshore well that offered ample workspace for the various service providers to learn the unique aspects of this rigless deployment. Of particular importance, the interface between the service providers at the surface cable termination was critical to the successful installation. For this trial test, the well completion was changed from 4½-in. tubing to 7-in. tubing to accommodate the cabledeployed 562 series ESP.

Lessons learned from this field trial will be incorporated into future trials of the technology. The goal of these future trials will be to deploy the technology in offshore H₂S wells where high rig costs can be significantly reduced through the use of lower cost barge coupled with increased speed, efficiency, and ease of CDESP deployment.

An ensemble-based 4D seismic history matching case is presented. Seismic data are re-parameterized as distance to 4D anomaly front and assimilated with production data. The field is a large turbiditic system, with initial fluid pressure close to the bubble point. Production causes the pressure to fall below the bubble point, resulting in a widespread gas-exsolution. The time-lapse change in gas saturation is considered responsible for the observed negative relative changes in seismic velocity seen over the all reservoir. This study is innovative for two reasons. First, the distance-to-front parameterization is applied to the gas-phase which appears everywhere in the field, rather than coming form an injection source like in previous application of the parameterization. Second, the binarization of the simulated time-lapse anomaly is performed circumventing the use of a petroelastic model; the petroelastic model would be necessary to relate the measurements to fluid properties changes and to decide a threshold for binarizing observations and pressure. However, the effect of gas is so widespread and evident that the petroelastic model is replaced by a clustering approach based on the gas saturation change of the reservoir cells. This study shows that adding the 4D re-parameterized seismic data in addition to the production data is keeping a reasonable match with production data while constraining the overall gas distribution in the reservoir to the observed seismic data.