Khuff-B and Khuff-C are the two carbonate reservoirs in the SA-1 field discovered in 1980 with the drilling of exploratory well SA-A. Production from Khuff-B began in December 1983 when a second well was drilled and both were put onstream. The development of Khuff-B was minimal until two years back and only nine stand-alone wells were exclusively completed in this reservoir at that time. Three of these nine wells were actually tied-in to the gas plant. Few other wells were combined Khuff-B/Khuff-C producers. In the commingled producers, Khuff-B’s contribution is significant only in areas where Khuff-C is of relatively poorer quality. The dominant production is generally from Khuff-C reservoir. A large area is currently within Khuff-B reservoir boundaries with only few producing wells. The development of this vast area is required to meet the increased gas demand. Accurate evaluation of Khuff-B to ascertain reservoir potential and deliverability is of utmost importance. This paper evaluates the Khuff-B reservoir in the SA-1 field and proposes an optimal development plan to effectively deplete its reserves. Based on detailed analyses, the Khuff-B area has been divided into three regions, namely AREA-1, AREA-2 and AREA-3: The good, moderate, and challenging low quality, tight reservoir. The average production rates from those areas vary between 5 and 50 MMSCFD. The optimal drilling plan in the low quality, low productivity area consists of identifying the productive layer through a slanted pilot hole followed by drilling an extended lateral to attain maximum reservoir contact. A second lateral can also be drilled in special cases where more than one developed layer is encountered in the pilot hole. This development approach also allows placing the production lateral much above the gas-water contact to avoid any future water production or influx. The strategy is promising, has already been implemented in the field, and the results have confirmed a high production, water-free gas rate from the Khuff-B interval.

Saudi Aramco is drilling horizontal wells along the minimum horizontal stress direction in an attempt to generate multiple transverse fractures during stimulation to increase gas production and enhance recovery. However, drilling operations in these wells are difficult due to wellbore instability because of the higher mud weights required to minimize formation breakout due to prevailing in-situ stress conditions. Increased mud weight also led to higher differential pressure across the variably depleted reservoir layers, which when coupled with formation instability, created greater challenges for the drilling team. These conditions resulted in a significantly increased number of stuck pipe incidents, incurring noticeably high nonproductive time including loss of bottomhole assemblies in the hole. To address these problems, an integrated approach between drilling expertise, applied geomechanics, and advanced mud logging technology was applied to successfully overcome stuck pipe events arising from wellbore instability and differential sticking. Additionally, the drilling and tripping practices were customized to confront borehole instability issues. Further, to account for formation heterogeneity and varying in-situ stresses, the predrill Mechanical-Earth-Model (MEM) was updated during drilling using Real-Time Drilling Geomechanics (RTDG). In addition, advanced cutting return-monitoring technology was used, which helped hole cleaning to minimize the risk of stuck pipe due to formation failure (excessive cuttings). An insight into the planning, challenges encountered, and procedures implemented to successfully drill the planned horizontal wells will be presented.

Horizontal Open Hole multistage fracturing (OHMSF) completion is the preferred completion to develop the tight and heterogeneous carbonate reservoir. Production data analyses and pressure transient tests are systematically and routinely conducted on these wells to determine the well productivity indices and evaluate key reservoir and fracture parameters. The OHMSF completions have been implemented since 2009 and have showed remarkable results compared to other completions and stimulation strategies such as vertical wells with single or multistage fracturing and open hole multilateral wells with maximum reservoir contacts. This paper presents the modeling and interpretation of production and actual pressure transient responses of horizontal OHMSF wells that were drilled in both the minimum horizontal stress (σmin) direction and the maximum horizontal stress (σmax) directions to assess the production and fracture behavior. Creating transverse fractures has shown better productivity compared to the longitudinal fractures in terms of production performance, which is corroborated in the paper through pressure transient analyses (PTA) and results from field data. The paper evaluates the impact of the fracture parameters such as fracture half length, conductivity, orientation, and number of fractures on production and pressure behavior. Well testing and production analyses tools are very powerful techniques to assess and compare different types of flow regimes for horizontal OHMSF wells drilled in different azimuth directions. This paper discusses and explains the different derivative shapes captured during well tests and compares these to the simulated and theoretical models. Also, the transmissibility values obtained from the mini falloff (MFO) test following during the fracture injectivity operations are compared with the flow capacity values calculated from the PTA. Challenges impacting pressure transient responses such as high wellbore storage are addressed in the paper and proper planning and use of best practices in the PTA to obtain accurate results are discussed and presented.

Cross-linked gel hydraulic fracturing fluid can induce high damage in the fracture when left for a long period of time. Any residual gel not produced back reduces the conductivity of the fracture and the well productivity, leading to an extended flowback for cleanup operation, which is not cost-effective.The objective of this study is to assess cleanup operation effectiveness by conducting laboratory testing on the flowback fluid samples from hydraulically fractured wells. These development wells are located in a clastic gas field in Saudi Arabia. This Devonian age reservoir has a range of permeability varying tight rocks of 0.1 md that require stimulation to highly prolific rocks with more than a Darcy that produce naturally. The laboratory analysis technique that was used for assessing the cleanup effectiveness is based on determination of the polymer content in the flowback fracturing fluid with a size exclusion chromatography (SEC). This laboratory technique provides the polymer concentration in the return fluid in a series of samples collected throughout the cleanup operation, and based on its results coupled with the production performance, the polymer strength of the residual fracturing fluids can be inferred. This study shows that the SEC technique is effective in qualitatively determining the polymer concentration trend with the flowback time, to assess the residual polymer content. The results are useful in establishing trends for the effective flowback practices based on different reservoir and fracture characteristics, even if fracturing fluids contain breaking agents. Using the laboratory results to optimize these parameters, formation damage can be minimized and well productivity will be ultimately enhanced.This paper summarizes results from the chemical analyses of the flowback fluids from three gas wells that help establish the basis for the flowback cleanup behavior, matched with the reservoir characteristics, fracturing design, fracturing fluid formulations; and concludes with operational recommendations. This study was conducted for the first time in this field with the goal of optimizing flowback duration and cost, and minimizing formation damage; and thereby enhancing well productivity.

A low permeability gas condensate carbonate reservoir in the Khuff formation is one of the main producing reservoirs in Field-A in Saudi Arabia. This early Triassic carbonate reservoir, first discovered in 1980, holds significant gas-in-place but is a blend of conventional and tight intervals. Vertical completions, horizontal wells with maximum reservoir contacts, and acid stimulation (matrix and fracturing) are some of the current practices to effectively develop the reserves from the tighter intervals. In late 2009, the open hole horizontal multistage fracturing (OHMSF) completion assemblies were deployed in several horizontal wells in the tight gas area with the goal of achieving multiple independent hydraulic fractures, greater acid stimulation efficiency, and thereby enhancing well productivity. The OHMSF systems enable the open hole section to be divided into segments based on the reservoir's petrophysical and flow properties by the use of mechanical open hole isolation packers and customizing the stimulation treatment for each segment via fracturing ports that are installed in between the packer assemblies. Since the inception of OHMFS, many wells were treated and varying results were obtained. The results are dependent not only on reservoir quality and development, but also on the placement of the fracturing ports, number of fracture stages conducted, and fracturing strategy. This paper provides insight into the planning, challenges encountered, sensitivity analysis and performance analysis of the OHMSF wells in comparison with non-OHMSF wells. It also details several case histories and highlights the results as well as lessons learned that can be applied in the future to improve the recovery.