Hydraulic Fracturing at Clair: Unlocking the Potential of Europe's Largest Reservoir

The Greater Clair area, Europe's largest oilfield, has two existing platforms, Clair Phase 1 and Clair Ridge, on production with future potential for a third platform targeting undeveloped Lower Clair Group to the South of Ph1. Clair Phase 1 was the initial development of Clair, targeting Lower Clair Group (LCG) reservoir consisting of a complex Devonian sandstone in six units. Most Phase 1 wells penetrated relatively good quality reservoir enhanced by natural fractures, while more recently Clair Ridge wells took a similar approach targeting natural fractures, however that strategy is continually being evaluated. In some areas however low matrix quality and lack of natural fractures were the dominant characteristics resulting in lower production rates. A brief comparison of the range of production outcomes will be presented, including potential downsides of reliance on natural fractures. Given the large oil volumes in areas of known poorer rock quality, alongside variable production results, a hydraulic fracturing trial was initiated in 2017. Well 206/08-A23 (A23) targeted previously under-developed, poor-quality Unit VI within the Phase 1 Graben area where natural fractures are absent. A pre-frac production test established baseline production of 900BOPD in December 2018. The A23 objectives included subsequent hydraulically fracturing the well to test this techniques ability to unlock production from tight, matrix dominated formation. Detailed analysis of core, log and limited vertical well fracturing data (from initial fracturing trials of 1980's vintage), yielded robust designs. Key challenges included overcoming very low KV/KH ratios with fracture heights exceeding 300ft. The resulting detailed designs provided consistent and predictable hydraulic fracturing execution in A23 in 2019, including placement of four planned 500klbs treatments combined with coil clean-outs after each stage to unload solids and fluids from the well. Initial fracture designs were conservative in terms of pad and proppant scheduling which, alongside learnings around operational logistics offshore West of Shetlands and completion design, offer significant optimisations for future hydraulic fractures. Post frac A23 became the highest non-natural fractured producer across Clair. Initially a six-fold production increase was observed with monitoring of transient production ongoing. Tracer analysis confirmed production contribution from all zones. Proving fracturing technology brings opportunities to unlock poorer Phase 1 and Ridge reservoir areas. Additionally, significant portions of the undeveloped Lower Clair Group to the South of Ph1 comprises lower permeability reservoir with higher viscosity oil and reduced natural fracture presence. Hydraulic fracturing is therefore a crucial completion technique for developing this lower quality reservoir and brings significant value enhancement to the project. Efficient delivery of numerous large fractures in a harsh offshore environment West of Shetlands presents significant challenges. The influence of how the A23 fracturing results and learnings are guiding future hydraulic fracturing concept are detailed, including optimising platform engineering design to facilitate efficient fracturing operations while maintaining the required productivity in this challenging scenario.

Track Fractured Well Inflow Performance Using Historic Production Logging and Surface Well Performance Data in Sultanate of Oman

PDO operates about 200 deep gas wells in the X field in the Sultanate of Oman, producing commingled from the Barik gas-condensate and Miqrat lean gas reservoir completed by multiple hydraulic fracturing. Their inflow performance relation (IPR) is tracked to diagnose condensate damage, hydraulic fracture cleanup and differential reservoir pressure depletion. The best IPR data is collected through multi-rate production logging but surface production data serves as an alternative. This paper describes the process of deriving IPR's from production logging and surface production data, and then evaluates 20 years of historic IPR data to quantify the impact of condensate damage and condensate cleanup with progressive reservoir pressure depletion, to demonstrate the massive damage and slow cleanup of hydraulic fractures placed in depleted reservoirs, to show how hydraulic fractures facilitate the vertical cross-flow between isolated reservoir intervals, and to highlight that stress-dependent permeability does not play a major role in this field.

A Novel Approach to Reservoir Simulation of Hydraulic Fractures: Performance Improvement Using Pseudo Well Connections

Reservoir simulation is used in most modern reservoir studies to predict future production of oil and gas, and to plan the development of the reservoir. The number of hydraulically fractured wells has risen drastically in recent years due to the increase in production in unconventional reservoirs. Gone are the days of using simple analytic techniques to forecast the production of a hydraulic fracture in a vertical well, and the need to be able to model multiple hydraulic fractures in many stages over long horizontals is now a common practice. The type of simulation approach chosen depends on many factors and is study specific. Pseudo well connection approach was preferred in the current case. Due to the nature of the reservoir simulation problem, a decision needs to be made to determine which hydraulic fracture modeling method might be most suitable for any given study. To do this, a selection of methods is chosen based on what is available at hand, and what is commonly used in various reservoir simulation software packages. The pseudo well connection method, which models hydraulic fractures as uniform conductivity rectangular fractures was utilized for a field of interest referred to as Field A in this paper. Such an assumption of the nature of the hydraulic fracture is common in most modern tools. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The pseudo well connection approach was found to be efficient both terms of replicating data of Field A for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.

Hydraulic Fracturing to Successfully Exploit Depleted Gas Reserves: A Case History from the North Sea

Hydraulic fracturing has been well established in the Southern North Sea (SNS) since the mid-1980s; however, it has typically been conducted as the final phase of development in new gas fields. One of these fields is Chiswick located in the Greater Markham area 90 miles offshore UK in 130 ft of water. Following an unsuccessful well repair of the multi-fractured horizontal well C4, it was decided to cost-effectively and expediently exploit the remaining pressure-depleted reserves near the toe via a single large fracture initiated from a deviated sidetrack wellbore designated C6. A deviated wellbore was chosen versus the original near-horizontal well to reduce well risk and costs and ultimately deliver an economic well. Several key challenges were identified, and mitigating measures were put in place. Modular formation dynamics tester data from the sidetrack open hole indicated the reservoir pressure gradient had depleted to 0.23 to 0.25 psi/ft, raising concerns about the ability of the well to unload the fluid volumes associated with a large fracture treatment. Wellbore deviation and azimuth with the associated potential for near-wellbore tortuosity would drive a typically short perforation interval (i.e., 3 ft). However, a compromise to mitigate convergent pressure loss in depletion was required, and the perforation interval was therefore set at 14 ft with provision made for robust step-down tests (SDT) and multi-mesh sand slugs. To further offset any near-well convergence pressure drop during cleanup, an aggressive tip screenout (TSO) proppant schedule, including a high concentration tail-in (12 PPA) with an aggressive breaker schedule, was executed to fully develop propped hydraulic width. Following formation breakdown and SDT to 40 bbl/min, the well went on near-instantaneous vacuum. Clearly, an extremely conductive feature had been created or contacted. However, upon use of a robust crosslinked gel formulation and 100-mesh sand, the bottomhole and positive surface pressure data allowed a suitable fracture design to be refined and placed with a large width, as evidenced by the extreme 2,309-psi net pressure development over that of the pad stage while placing 500,500 lbm of 16/30 resin-coated (RC) intermediate strength proppant (ISP) to 12 PPA. Although a lengthy nitrogen lift by coiled tubing (CT) was planned, the well cleanup response in fact allowed unaided hydrocarbon gas flow to surface within a short period. The well was then further beaned-up under well test conditions to a flow rate of approximately 26 MMscf/D under critical flowing conditions with a higher bottomhole flowing pressure than that of the original C4 well. Given the last producing rate of the original multiple fractured horizontal wellbore was 27 MMscf/D at a drawdown of 1,050 psi through two separate hydraulic fractures, then the outcome of this well was judged to be highly successful and at the limit of predrill expectations. This case history explains and details the rationale, methods, and techniques employed in well C6 to address the challenge of successful hydraulic fracture stimulation in a depleted formation. Challenges were addressed by combining a number of techniques, coupled with field experience, resulting in a highly productive well despite the relatively low reservoir pressure coupled with a limited time frame to plan and execute. These techniques are transferrable to other offshore gas fields in the region where reservoir depletion makes economic recovery difficult or indeed prohibitive.

Numerical Simulation Study of Proppant Transport in Cross Fractures

Hydraulic fracturing technology is an important means to stimulate unconventional reservoirs, and the placement morphology of proppant in cross fractures is a key factor affecting the effect of hydraulic fracturing. It is very important to study the proppant transport law in cross fractures. In order to study the proppant transportation law in cross fractures, based on the CFD-DEM method, a proppant transport model in cross fractures was established. From the two aspects of the flow field in the fractures and the morphology of the proppant dune, the influence of the natural fracture approach angle, the fracturing fluid viscosity and injection rate on the proppant transport is studied. Based on the principle of hydropower similarity, the conductivity of proppant dune under different conditions is quantitatively studied. The results show that the natural fracture approach angle affects the distribution of proppant and fracturing fluid in natural fractures, and further affects the proppant placement morphology in hydraulic fractures and natural fractures. When the fracturing fluid viscosity is low and the displacement is small, the proppant forms a "high and narrow" dune at the entrance of the fracture. With the increase of the fracturing fluid viscosity and injection rate, the proppant settles to form a "short and wide" placement morphology. Compared with the natural fracture approach angle, the fracturing fluid viscosity and injection rate have a more significant impact on the conductivity of proppant dune. This paper investigated the proppant transportation in cross fractures, and quantitatively analyzes the conductivity of proppant dunes with different placement morphology. The results of this study can provide theoretical guidance for the design of hydraulic fracturing.

Optimist, Pessimist or Engineer - Conductivity Based on Need Not Fashion

An optimist says the glass is half-full, a pessimist half-empty, whereas a good engineer says that the glass is twice as big as it needs to be. There has been much debate over the years about the relative functionality, application and even necessity of proppant in delivering effective hydraulic fractures. Often these debates have been directly linked to major changes in core frac applications, more recently in the dominant North American onshore unconventional market. However, the debates have all too often used broad or unclear brush strokes to describe shifting fracture requirements. Meanwhile, the developing oilfield in the rest of the world resides in more permeable areas of the resource triangle, great care must be taken to ensure that conventional lessons hard learned are not lost, but also that unconventional understanding develops. Over recent years there have been many debates and publications on the relative value of the use of proppant (and associated conductivity), although the true question was about appropriate fracture design in different rock/matrix qualities and environments. Certainly, the vast majority of fracturing engineers appreciate the difference between continuous proppant-pack conductivity and other techniques, such as infinite conductivity, pillar fracturing or duning designs. However, there is increasing evidence that conventional fracturing is suffering from populist attitudes, leading to ineffective fracturing. Additionally, and just as impactful, that unconventional fracturing continues to rely on the lessons learned and physics derived directly from our conventional experience but applying this in an entirely different environment. Primarily, the main concern is with the transfer of recent lessons learned and techniques utilised in one rock quality and environment, to an entirely different scenario, resulting in the misapplication, reduced IP30, poorer NPV or reduced long term EUR and IRR. Examples will be referenced where appropriate proppant selection and frac design can be the difference between success and failure. Fundamentally, we have not sufficiently developed our understanding of the role of proppant and conductivity, for application in unconventionals and thereby rely far too much on our previous conventional thinking. While at the same time we are exporting often inappropriate unconventional populist practice into very conventional environments, thereby potentially achieving the abhorrence of the worst of both worlds. This paper will describe and address scenarios where appropriate engineering selection, rather than popularity-based decision making, has resulted in a successful outcome. It will also attempt to ensure that we show the importance of studying your rock, in anticipation of engineering design, and that this should be a key consideration. The paper will also suggest that as an industry we urgently need to address our approach to consideration of conductivity, placement and importance and ensure that unconventional knowledge and learning progresses with a beneficial outcome for all.

Achieving Productivity and Clean Inflow from an Unconventional Reservoir in North Kuwait

Jurassic Kerogen shale/carbonate reservoir in North Kuwait provides the same challenges as North American shales in addition to ones not yet comparable to any other analogue reservoir globally. It is the Kerogen's resource density; however, that makes this play so attractive. Like ‘conventional’ unconventional in the US and Canada this kerogen is believed to be a source rock and is on the order of micro-to nano-Darcy permeability. As such, industry learnings show that likely long horizontal laterals with multiple hydraulic fractures will be necessary to make commercial wells. Following this premise, the immediate objective is to establish clean inflow into wellbore as the previous attempts to appraise failed due to "creep" of particulate material and formation flowing into the wellbore. Achieving this milestone will confirm that this formation is capable of solids free inflow and will open a new era in unconventional in Kuwait. Planning for success, the secondary objective is to then upscale to full field development. The main uncertainties lie in both producibility and ‘frac-ability’, and certainly, these challenges are not trivial. A fully integrated testing program was applied to both better understand the rock mechanical properties and to land on an effective frac design. Scratch, unconfined stress, proppant embedment and fluid compatibility tests were conducted on full core samples for geo-mechanics to prepare a suite of strength measurements ahead of frac design and to custom-design the fracture treatment and "controlled" flowback programs to establish inflow from Kerogen without "creep". Unlike developed shale reservoirs, the Jurassic Kerogen tends to become unconsolidated when treated. The pre-frac geomechanics tests will be outlined in this paper with the primary objective of finding the most competent reservoir unit to select the limited perforation interval to frac through so that formation competency can be maintained. Previous attempts failed to maintain a competent rock matrix even only after pumping data-fracs. Acidizing treatments also turn the treated rock volume into sludgy material with no in-situ stability nor ability to deliver "clean inflow". A propped fracturing treatment with resin-coated bauxite was successfully placed in December 2019 in a vertical appraisal well perforated over 6 ft at 12 spf shot density. "Controlled" flowback carried out in January 2020 achieved the strategically critical "clean inflow" with reservoir fluids established to surface. Special proppant technologies provided by an industry leading manufacturer overcame the embedment effects and to control solids flowback. A properly designed choke schedule to balance unloading with a delicate enough drawdown to avoid formation failure was executed. Local oilfields relied on the vast reserves and produced easily from carbonate reservoirs that required only perforating or acid squeezes to easily meet or exceed high production expectations. This unconventional undertaking in Kuwait presents a real challenge as it is a complete departure from the ways of working yet it points towards a very high upside potential should the appraisal campaign can be completed effectively.

Integrated Hydraulic Fracture Geometry Evaluation Based on Pre-Cambrian Tight Silicylate Reservoir in South Oman Salt Basin

Pre-Cambrian South Oman tight silicilyte reservoirs are very challenging for the development due to poor permeability less than 0.1 mD and laminated texture. Successful hydraulic fracturing is a key for the long commercial production. One of the main parameter for frac planning and optimization is fracture geometry. The objective of this study was summarizing results comparison from different logging methods and recommended best practices for logging program targeting fracture geometry evaluation. The novel method in the region for hydraulic fracture height and orientation evaluation is cross-dipole cased hole acoustic logging. The method allows to evaluate fracture geometry based on the acoustic anisotropy changes after frac operations in the near wellbore area. The memory sonic log combined with the Gyro was acquired before and after frac operations in the cased hole. The acoustic data was compared with Spectral Noise log, Chemical and Radioactive tracers, Production Logging and pre-frac model. Extensive logging program allow to complete integrated evaluation, define methods limitations and advantages, summarize best practices and optimum logging program for the future wells. The challenges in combining memory cross-dipole sonic log and gyro in cased hole were effectively resolved. The acoustic anisotropy analysis successfully confirms stresses and predominant hydraulic fractures orientation. Fracture height was confirmed based on results from different logging methods. Tracers are well known method for the fracture height evaluation after hydraulic frac operations. The Spectral Noise log is perfect tool to evaluate hydraulically active fracture height in the near wellbore area. The combination of cased hole acoustic and noise logging methods is a powerful complex for hydraulic fracture geometry evaluation. The main limitations and challenges for sonic log are cement bond quality and hole conditions after frac operations. Noise log has limited depth of investigation. However, in combination with production and temperature logging provides reliable fit for purpose capabilities. The abilities of sonic anisotropy analysis for fracture height and hydraulic fracture orientation were confirmed. The optimum logging program for fracture geometry evaluation was defined and recommended for replication in projects were fracture geometry evaluation is required for hydraulic fracturing optimization.

Estimation of Fracture Properties by Combining DAS and DTS Measurements

Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) measurements during hydraulic fracturing treatments are used to estimate fluid volume distribution among perforation clusters. DAS is sensitive to the acoustic signal induced by fluid flow in the near-well region during pumping a stage, while DTS is sensitive to temperature variation caused by fluid flow inside the wellbore and in the reservoir. Raw acoustic signal has to be transferred to frequency band energy (FBE) which is defined as the integration of the squared raw measurements in each DAS channel location for a fixed period of time. In order to be used in further interpretation, FBE has to be averaged between several fiber-optic channels for each cluster on each time step. Based on this input, DAS allows us to consider fluid flow through perforation stage by stage during an injection period, and to evaluate the volume of fluid pumped in each cluster location as a function of time, and therefore to estimate the cumulative volume of fluid injected into each cluster. This procedure is based on a lab-derived and computational dynamics model confirmed correlation between the acoustic signal and the flow rate. At each time step, we apply the perforation/fracture noise correlation to determine the flow rate into each cluster, constrained by the requirement that the sum of the flow rates into individual clusters must equal the total injection rate at that time. On the other hand, the DTS interpretation method is based on the transient temperature behavior during the fracturing stimulation. During injection, the temperature of the reservoir surrounding the well is cooled by the injection fluid inside the well. After shut-in of stage pumping, temperature recovers at a rate depending on the injected volume of fluid at the location. The interpretation procedure is based on the temperature behavior during the warm-back period. This temperature distribution is obtained by solution of a coupled 3-D reservoir thermal model with 1-D wellbore thermal model iteratively. Once we confirm that the DAS and DTS interpretation methods provide comparable results of the fluid volume distribution, either of the interpretation results can be used as a known input parameter for the other interpretation method to estimate additional unknown such as one of the fracture properties. In this work, the injected fluid volume distribution obtained by the DAS interpretation is used as an input parameter for a forward model which computes the temperature profile in the reservoir. By conducting temperature inversion to reproduce the temperature profile that matches the measured temperature with the fixed injection rate for each cluster, we can predict distribution of injected fluid for hydraulic fractures along a wellbore. The temperature inversion shows that multiple fractures are created in a swarm pattern from each perforation cluster with a much tighter spacing than the cluster spacing. The field data from MIP-3H provided by the Marcellus Shale Energy and Environmental Laboratory is used to demonstrate the DAS/DTS integrated interpretation method. This approach can be a valuable means to evaluate the fracturing treatment design and further understand the field observation of hydraulic fractures.

Experimental Investigation of Seepage Mechanism on Oil-Water Two-Phase Displacement in Fractured Tight Reservoir

As a type of unconventional oil and gas resources, tight sandstone reservoir has low permeability and porosity properties and thus is commonly necessary to develop through hydraulic fracturing treatment. Due to the coexistence of natural fractures and induced hydraulic fractures, the heterogeneity of reservoir permeability becomes severe and therefore results in complicated fluid seepage mechanism. It is of significance to investigate the oil-water two-phase seepage mechanics before and after the hydraulic fracturing stimulation with the aim of supporting the actual production and development of oilfield. This paper experimentally investigated the influences of fracture system on seepage characteristics of two-phase displacement in sample cores of fractured tight sandstones. In details, the changes of injection rate, cumulative production rate, recovery ratio, and water content were analyzed before and after the hydraulic fracturing treatments. To further analyze the displacement characteristics of the sample core, the displacement indices of four rock samples in different displacement stages were investigated. The sensitivity of sample core displacement indices to many key factors, including injection time, oil production rate, oil recovery factor and injection multiple factor, and moisture (i.e., water content was 95%, 98%, and 99.5%, respectively), before and after the hydraulic fracturing treatments were obtained synthetically. Besides, the relationship between recovery difference and contribution of fracture to permeability was explored at different water contents. The experimental results reveal that the fracture system shortens the water-free production period and hence reduces the recovery rate. The greater the contribution of fractures to permeability, the lower the recovery of water during this period.