horizontal well
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Abstract The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.

Abstract 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.

Abstract The carbonate reservoir S is a giant limestone reservoir in H Oilfield, Iraq. Although the reserves account for 25%, the production contribution is only 0.4% to the total oilfield production due to poor petrophysical properties. Accordingly, the first proppant fracturing on vertical well was successfully executed in December 2016, which has already achieved a steady production period over than 3 years. In order to further improve the productivity, the first multi-stage proppant fracturing(MSPF) on horizontal well(SH01X) was successfully applied in November 2019, a technique which is rarely reported for porous limestone reservoir in the Middle East. Proppant fracturing in carbonate reservoirs is a technique difficulty worldwide, especially this is a lack of experiences in the Middle East. To ensure the success of this campaign, a holistic technical study including geology evaluation, reservoir performance analysis, drilling trajectory design, completion and fracturing technique design have been carried out based on principle of "geology-engineering integration". This paper will present a comprehensive illustration including treatment design (main completion-fracturing technique, total scale, fracturing fluid, proppant), job execution (mini-frac, main-frac) and post-frac production performance for this successful campaign. True vertical depth (TVD) of Well SH01X is 2720 m and the horizontal section length is 811 m. Based on the main technique of multi-stage proppant fracturing with open hole packers and sliding sleeves, totally 3784.3 m3 fracturing fluid and 452 m3 proppant were pumped in 8 stages. The test production was 3214 BOPD (choke size: 40/64", wellhead pressure: 970 psi). A historical breakthrough in the productivity of S reservoir has been achieved by the campaign. The post-frac evaluation shows that the treatment parameters are consistent with the design. The connectivity between artificial fractures and formation is greatly improved, and the stimulation effect is significant. Currently the "production under controlled pressure" mode has been executed and the stable production under stimulation target rate has been maintained. The systematic "geology-engineering integration" workflow is of significance to the success of the treatment as well as the stimulation effect. MSPF is planned to be a game-changing technique to develop the huge reserves of S reservoir. The experience gained from this case could provide theoretical as well as practical references for similar reservoirs in the Middle East.

Abstract Efficient multistage hydraulic fracturing in horizontal wells in tight-gas formations with multilayered and laminated reservoirs is a very challenging subject matter; due to formation structure, required well trajectory, and the ability to establish a conductive and permanent connection between all the layers. BP Oman had initiated the technical journey to deliver an effective horizontal well multistage frac design through learnings obtained during three key pilot horizontal wells. Since these initial wells, additional candidates have been drilled and stimulated, resulting in further advancement of the learning curve. Many aspects will be covered in this paper, that will describe how to facilitate the most effective hydraulic fracture placement and production performance, under these laminated conditions. These approaches will include the completion and perforation selection, fracture initiation zone selection, fracture height consideration, frac fluid type and design. The paper will go on to describe a range of different surveillance options, including clean-up and performance surveillance as well as number of other factors. The experiences that have been gained provide valuable insight and learning about how to approach a multistage fracturing horizontal well program in this kind of depositional environment. Additionally, how these lessons can potentially be subsequently adapted and applied to access resources in the more challenging and higher risk areas of the field. For example, this paper will present direct comparison of over and under-displaced stages; differences in execution and production for cased hole and open hole completions; and many other variables that always under discussion for hydraulic fracturing in horizontal wells. This paper describes in detail the results of many multistage fracturing trials by BP Oman in horizontal wells drilled in challenging multilayered and laminated tight-gas reservoirs. These findings may help to cut short learning curve in similar reservoirs in the Middle East Region and elsewhere.

AbstractHorizontal wells play an often overlooked role in hydrogeology and aquifer remediation but can be an interesting option for many applications. This study reviews the constructional and hydraulic aspects that distinguish them from vertical wells. Flow patterns towards them are much more complicated than those for vertical wells, which makes their mathematical treatment more demanding. However, at some distance, the drawdown fields of both well types become practically identical, allowing simplified models to be used. Due to lower drawdowns, the yield of a horizontal well is usually higher than that of a vertical well, especially in thin aquifers of lower permeability, where they can replace several of the latter. The lower drawdown, which results in lower energy demand and slower ageing, and the centralized construction of horizontal wells can lead to lower operational costs, which can make them an economically feasible option.

One of the modern approaches for the effective development of small deposits is the construction and operation of wells with a complex architecture: horizontal wells (HW), sidetracks (BS, BGS), multilateral wells (MLW). Sidetracking makes it possible to reanimate an old well that is in an emergency state or inactivity for technological reasons, by opening layers that have not been previously developed, bypassing contamination zones, or watering the formation. This study examines the possibility of using horizontal sidetracks in the operating wells of the field of the Zhetybai group. To select the optimal length of the horizontal sidetrack of the wells, graphs of the dependences of the change in flow rate versus length of the horizontal well were built, taking into account the pressure losses due to friction. It can be seen from the dependence of NPV versus length of the horizontal wellbore that the maximum NPV is achieved with a horizontal wellbore length of 100 m. A further increase in the length of the horizontal wellbore leads to a decrease in NPV. This is due, firstly, to a decrease in oil prices, and secondly, interference of wells, a small number of residual reserves, and a small oil-bearing area. As a result of a comparison of technical and economic criteria, the optimal length of a horizontal wellbore is from 100-300 meters. Comparison of the flow rates of vertical wells and wells with horizontal sidetracks showed a clear advantage over the latter in all respects.