Well intervention

Successful Recovery and Stimulation in a Long HP/HT Horizontal Well in One Intervention

The case history presented in the complete paper describes the performance of an acid-fracturing intervention in an HP/HT well in which this intervention was the last procedure considered to evaluate the productivity of a Marrat Formation well.


The case history presented in the complete paper describes the performance of an acid-fracturing intervention in a high-pressure/high-temperature (HP/HT) well in which this intervention was the last procedure considered to evaluate the productivity of a Marrat Formation well. The post-acid-fractured well productivity index (PI) showed the high quality of the stimulation performed in a challenging environment, demonstrating the effectiveness of the new diversion system for creating selective fractures in a horizontal wellbore with multiple perforation clusters.


Completion of deep HP/HT carbonate formations in northern Kuwait in overpressured environments comprising interbedded carbonate bodies, complex tectonics, and stress variations resulting in strike/slip or reserve fault regimes is challenging for operator and service companies. Because of the low-permeability conditions, it is necessary to generate long and conductive fractures to produce the reservoir effectively. Additionally, this aggressive fracture-stimulation requirement needs to overcome the high-working-pressure limitations of the completion, in addition to the nature and corrosiveness of the produced hydrocarbon, which makes selection of the proper stimulation reactive-fluid system important.

These challenges are even more crucial in cases having drilling and completions issues. The alternative implemented for the well candidate presented in the complete paper considers the completion and stimulation of a well having an existing long perforated interval, where the implementation of a selective fracture stimulation of a highly deviated wellbore (88° or almost horizontal) was challenging.

Geology, Reservoir, and Geomechanics of Middle Marrat Formation

The Marrat reservoir is subdivided into three lithostratigraphic units: Lower, Middle, and Upper. The well candidate was drilled and completed to produce hydrocarbon reserves from the Middle Marrat Formation. The Middle Marrat unit represents a wide range of rock types related to high-stand precursor facies in a carbonate setting, which is overprinted by diagenetic alteration in refluxed and recrystallized dolomites. Eight gross flow zones have been identified bounded by major sequence-stratigraphic surfaces that frame the background of genetically correlated units.

Reservoir quality and vertical connectivity can be controlled further by placing properly distributed hydraulic fractures, vertically and laterally, to connect the prospective reservoir and existing natural-fracture networks to improve ­hydrocarbon recovery.

The candidate well has a reservoir pressure of 7,521 psi in the completed horizontal section. The horizontal wellbore was almost aligned with the maximum stress orientation, meaning that any hydraulic fracture generated in the well would be longitudinal and the length of the perforations would not need to be limited as it is in cases where transverse fractures are generated.

Well-Candidate Completion Information

Drilling issues experienced during the construction of the last section of the wellbore resulted in leaving the drilling bottomhole assembly and in protracted attempts to recover the fish in hole. Eventually, it was decided to sidetrack and drill a second lateral. Because of budget constraints and the long drilling-rig time associated with the fishing process, additional wellbore logging was eliminated to minimize operational costs. A whipstock was set in the original 10¾-in. casing above the abandoned horizontal leg, and an exit window was milled. An inclined 9¼-in. exit hole was drilled for just over 400 ft, and 7⅝-in. liner was set from the surface to 15,874-ft measured depth (MD) after drilling the new lateral leg to just past 19,000-ft MD.

The newly drilled wellbore was completed with a 5-in. cemented liner with a landing shoe at 18,964-ft MD. After cleaning the wellbore and evaluating the cement bonding in the bottom liner, the wellbore was perforated with 2⅞-in. tubing-conveyed perforating guns in three intervals of 126, 120, and 120 ft, respectively, in order of shooting (total perforated interval of 415 ft with 365 ft perforated). After running 3½-in. tubing from the surface to the sealbore located in the liner hanger, the well was opened to production to evaluate Lower Marrat Formation productivity. How­ever, because of damage induced during the ­drilling process and poor well productivity, a conventional matrix acidizing using 150 bbl of 15% hydrochloric acid plus chemicals was squeezed in one stage at a low rate of 1.1 bbl/min in the open intervals. This stimulation treatment did not improve productivity, and the well ended up dying.

The poor well productivity and challenges imposed by the nature of the formation and the existing completion justified using a new, more-aggressive stimulation treatment to produce the Middle Marrat Formation.

Fracture-Acidizing-Stimulation Design

Considering the alignment of the wellbore, the maximum-stress orientation in the area, and the length of each perforated interval, an innovative acid-fracturing design was needed to induce at least one selective hydraulic fracture in each perforated interval, anticipating fracture orientations at only a small angle from the wellbore direction.

An injectivity and minifracturing procedure considering a nonreactive fracturing fluid was included as a part of the fracture-stimulation process to allow calibrating the stress profile calculated from the offset-well log data, to identify the existing completion and near-wellbore (NWB) effects and challenges, and to estimate the reservoir pressure and fluid-efficiency effects expected during the stimulation process.

The designed acid-fracture-pumping schedule included sequential pumping of three different acid-fracturing stages spaced with two diversion systems to allow acid-fracturing stimulation of the perforated intervals by diverting the stimulation fluid in the wellbore, thereby generating one selective fracture per perforated interval.

Diversion Systems Used To Optimize the Acid-Fracturing Stimulation

Two different diversion systems (a solids-free liquid fluid-loss-and-­diversion system and a self-degrading-solid diversion system) were proposed and used in the field to help reduce fluid leakoff, improve the reactive-fluid coverage, and generate selective acid fractures in each perforated interval.

The solids-free fluid-loss-and-diversion system is a low-viscosity fluid-loss-control system used over a broad range of temperatures and permeabilities in oil or gas carbonate formations. This system decreases matrix permeability to aqueous fluids, limiting leakoff into treated zones; it requires no breaker and results in little or no damage affecting the flow of hydrocarbons.

The self-degrading-solid diverter is used with nonreactive or reactive-acid systems to divert stimulation fluid into the wellbore/perforations or deeper in the reservoir, in both carbonate and sandstone formations. This system is a combination of particles of specific sizes and hardness values contained in a single package. The system’s loading and particles are designed to address specific problems. Particle-size ratios are specifically sized so that larger particles restrict or divert the stimulation-fluid flow in the perforations and the smaller particles pack the pore throats of the larger particles or the existing natural fractures. This leads to quick and efficient blockage of the induced fractures.

The particles of the self-degrading-solid diverter are designed to degrade over time at temperature. This helps eliminate the cost, time, and effort necessary to use remedial removal techniques. The degradation product is compatible with produced hydrocarbons and produced water.

Prefracturing Diagnostic-Procedure Analysis

The required injectivity, step-rate-up (SRU), step-rate-down (SRD), and minifracturing-diagnostic procedures were performed and analyzed as planned.

The SRU analysis showed a fracture-extension rate of 12.48 bbl/min, where the fracture was approximately aligned along the length of the perforated interval with the expected high leakoff necessary to keep the induced fracture open. Conversely, the SRD analysis was magnified by the NWB friction effect, which was associated with the complexity of the induced fracture resulting from the length of the perforation and the orientation of the wellbore. Additionally, the minifracturing-analysis results, assuming that only one primary fracture was generated during this step, showed the typical pressure-dependent-leakoff effect observed in almost all carbonate formations, while the calculated minimum stress was 13,111 psi (0.85 psi/ft) and the average nonreactive-crosslinked-fluid efficiency was 30%.

The calculated parameters from the diagnostic procedures were used to optimize the main acid-fracturing-stimulation process.

Post-Fracturing Well-Production Evaluation

After analyzing all diagnostic procedures considered for the acid-fracturing stimulation, the pumping schedule for the main acid-fracturing stimulation was redesigned (see Table 4 of the complete paper). The excellent match obtained during pumping and when the treatment was stopped indicates the quality of the considered rock and reservoir parameters and the obtained fracture parameters.

The main selective acid-fracturing-stimulation treatment increased the well production rate from 677 to 1,307 BOPD, considering the same choke size for fair comparison purposes. After the acid fracturing performed on 29 May 2016, the well was opened to production the following day. The first day’s measured transient fluid-production rate was high and showed a high water cut. The measured initial high water cut corresponded to the stimulation fluid returning and not to formation-water production. The initial well response showed the positive effect of the selective acid-fracturing treatment performed in the well. However, the well was not tested periodically after the acid-fracturing treatment to determine the stability of the oil- and gas-­production-rate trend up to 8 December 2016 (Fig. 1). The latest test showed the ability of the selective acid-fracturing treatment to re-establish productivity and produce hydrocarbon reserves effectively from the Middle Marrat Formation connected to the wellbore.

Fig. 1—Comparative production before and after selective acid fracturing.


This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188567, “Successful Recovery and Stimulation of a Long HP/HT Horizontal Well in One Intervention: A Case History of Acid Fracturing and New Generation of Diversion Systems Combination, Middle Marrat Carbonate Formation,” by Leopoldo Sierra, Alaa Eldine Alboueshi, Mohamed Elmofti, Walid Eid, Salma Sadeddin, and Ahmed Allam, Halliburton, and Mohamed Al Othman, Zamzam Ahmed, Erkan Fidan, Ibrahim Al-Zaidani, Neoq Nilotpaul, Meshari Ashkanani, Ali Buhamad, Mohammed Abdullah Al-Dousari, Abdul-Samad Mohammed Ahmed, and Yousef Al-Matrouk, Kuwait Oil Company, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed.