Development drilling operations in the Zuluf Field / Khafji Reservoir (offshore Saudi Arabia) involve targets near the flanks of the main structure, where oil-filled sands are sandwiched between overlying gas and underlying water. Horizontal well technology is utilized to increase the reservoir footprint. This article relays recent geosteering examples in the Khafji Sand bodies. Demonstrated results show significant gains in well productivity through an advanced well placement procedure relying on real-time geosteering. An asset team implemented a process of well placement in order to maximize the reservoir contact while drilling1. The process involves continuous exchange of information between the well site and the office-based teams to allow fast and informed decisions. The success of the well placement process has been enhanced by preparation prior to drilling, continuous interpretation of the real time data while drilling and integrated teamwork throughout the project. A key technology in the well placement process is the use of realtime borehole density images in addition to the standard LWD data. Continuous interpretation of the image data (providing bed dip and thickness) and correlation of the LWD data, with the offset well data and geological models, provided the information necessary to maximize the reservoir contact "net pay" along the horizontal lateral section. A series of wells have been drilled using the advanced well placement process. Examples illustrate how real time interpretation of the data by the team increased the net to gross ratio from 35% to 50%. The resultant increase in production demonstrates the value and the necessity of the process in the ongoing development of the field. Introduction The Zuluf field is located in the Arabian Gulf, approximately 149 miles (240 kilometers) north of Dhahran, Saudi Arabia, in an average water depth of 118 feet. Discovery of the field was made in 1965 and 270 wells have been drilled to date. The Khafji Reservoir is part of the Khafji Member of the Middle Cretaceous, Wasia Formation. The Khafji Member conformably overlies the Lower Cretaceous, Shu'aiba Formation and in turn is conformably overlain by the Safaniya Member. The Khafji reservoir in the Zuluf field consists of a thick sequence of quartz-rich sandstones, siltstones, shales and various types of ironstones (siderite, chamosite, and glauconite). Minor amounts of limestone and a few coal beds are also present. The average reservoir porosity is 30 percent and average permeability is greater than 1 Darcy. The Khafji reservoir was deposited in a fluvial-dominated delta system which prograded over the shallow marine carbonate platform of the Shu'aiba Formation. The Khafji Member ranges from 625 to 875 feet in thickness and is subdivided into four major stratigraphic units (figure 1). The uppermost unit, the "Upper Khafji Shale", is essentially shale with occasional thin reservoir sands. The next unit, the "Upper Khafji Stringers", consists of interbedded sands and shales with minor amounts of ironstone (mainly siderite), and very thin coal layers. Below the stringer sands is the "Main Sand", made up of thick massive sands 200 to 300 feet thick. The lowermost unit, the "Lower Khafji Stringers", is predominantly shale with minor interbedded reservoir sands. The majority of wells drilled to date are vertical and have targeted the "Main Sand" member. As drilling technology has advanced it has now become possible to target additional pay-zones within the "Upper Khafji Stringers" which are best developed on the flanks of the reservoir structure.

The presence of fractures in reservoirs can have a large impact on short and long term production. Electrical imaging tools have a long history in the identification and quantification of fractures in boreholes drilled with water base muds. These tools are particularly sensitive to conductive fractures. The width (also known as aperture) of open fractures is calculated by a well-established equation, relating the fracture width to the excess current measured by the imaging tool (Luthi and Souhaité, 1990). Both mud resistivity and background resistivity of the formation need to be known or measured. The equation was derived from 3-D finite element modeling of the borehole imaging tools of the time. Recent work has revisited the fracture aperture calculations. The work has verified the approach for electrical imaging from modern wireline tools and extended the principle to Logging While Drilling (LWD) tools. A twofold approach has been taken for the work. Firstly 3-D finite element modeling had been carried out. This includes detailed modeling of the tool sensors' geometry and the analysis of the electromagnetic responses when the sensors are passed in front of a range of fracture widths. The modeling is complemented by a series of physical experiments carried out at Delft University. Setups utilized either a wireline pad or an LWD sensor from the relevant imaging tools. The sensors were traversed across two blocks separated by a precisely measured gap. Measured excess current relates to the fracture apertures and verifies the theoretical modeling work. This combined work confirms the equation for the fracture aperture calculation. In addition the coefficients for both the modern wireline and LWD electrical imaging tools are determined. Workflows for the quantification of conductive fractures identified on borehole images have been refined and implemented. Fractures are commonly not continuous across the borehole. The workflow includes a fast automatic extraction of both discontinuous and continuous fracture segments. Fractures are grouped into sets based on relevant criteria (such as orientation). Apertures are calculated using the relevant tool coefficients. The fracture density and porosity are then accurately computed along the well. This enables quantification and characterization of the fracture network, including a fast and easy recognition of intervals with specific aperture or porosity ranges. The workflow is demonstrated by examples.

No abstract

A number of calipers and hole size indicators (be they by direct measurement or derived) have been introduced with the logging while drilling (LWD) suite of measurements. These include ultrasonic calipers, derived density calipers, and electrical calipers from resistivity tools. Qualitative indications of borehole shape can also be derived from Pe and density measurements which can be affected by tool standoff. The traditional uses of borehole shape measurements have been principally aimed at petrophysicists, reservoir engineers, and geologists for completion strategy, hole volume determination, correction of electrical logs, borehole stability, and borehole size for images. In this paper we summarize additional applications for drillers:To assess the borehole quality related to the drilling process and borehole assembly being used.To diagnose wellbore stability problems while drillingTo identify hole quality which may affect running the completion or wireline tools Hole shape analysis is carried out by processing azimuthal ultrasonic caliper, Pe, and density data into 1D, 2D, or 3D images to illustrate the borehole shape. Processing of images or caliper curve data in real time enables decisions to be made about modification of the BHA or reconsider drilling practice for the remainder of the well. An obvious application of the images is to visualise the severity and nature of any borehole breakout occurring and to take necessary steps to resolve the problem, for example by increasing mud weight. Our results of processing a number of wells highlight that in many cases the shape of the borehole can be directly related to the drilling process. Examples are shown of boreholes drilled by rotary steerable assemblies and mud motors (with different stabilizer configurations and different drilling modes). Timely feedback of this information to the driller allows changes in the style of drilling or BHA to improve the borehole shape and therefore drilling efficiency. This in turn should lead to an improved shaped borehole and better petrophysical data. Understanding the effects of the drilling process can also allow differentiation of drilling induced shape artefacts and geological reasons for borehole shape changes (e.g. zones of instability or breakout). Information on the shape of the borehole also improves the decisions made for completion strategies where mechanical calipers are not being run. Applications include understanding borehole shape for expandable screens and cement volumes. Introduction Caliper information has been available for a number of years from Logging While Drilling tools1,2. These are all derived measurements rather than a physical measurement of the borehole size. In other words there are not mechanical arm calipers at the time of drilling. The caliper measurements are derived from a variety of measurements that have differing volumes of investigation and therefore differing applications. This paper concentrates on applications of quantitative ultrasonic caliper measurements with a particular focus on the drilling applications. The focus has been placed on the drilling side because it is felt that there are a considerable number of applications for the improvement of the drilling process by the interpretation of borehole shape information. The quantitative caliper information is supplemented by qualitative hole shape information form Photoelectric and density images. Whilst analysis of hole shape can be done after the well has been drilled, the improving rates of real-time data transmission now allow the borehole to be imaged in real time. This allows recognition of variations in borehole shape at the time of drilling and allows changes in the drilling practice to optimize the shape and therefore drilling efficiency. The paper will discuss the ultrasonic caliper measurement and then discuss the applications and limitations in more detail.

The interest in exploring carbonate reservoirs has experienced a rapid growth in south-east Asia. However, significant drilling hazards have been encountered where karstification and fractures are present. This led to deployment of pressurised-mud-cap drilling (PMCD) to address total losses. PMCD involves drilling with no returns to surface, while drilled cuttings are injected back to the lost circulation zones. Under the PMCD conditions, wireline logging is usually ruled out, making logging-while-drilling (LWD) the only choice. PMCD often induces adverse borehole conditions such as enlarged hole and deep early time invasion, which affect log responses and challenge interpretation. PETRONAS has reported several wells in which well logs were badly affected when PMCD was activated. A recent carbonate gas well illustrates the impact on LWD responses of the deep invasion and borehole deterioration associated with PMCD. A multifunction LWD tool providing triple-combo logs, sigma, and spectroscopy measurements was combined with a high-resolution resistivity imaging tool to identify the gas-water contact. The hole was enlarged up to 10-inches, in contrast to the 8 ½ inch bit size. Reservoir evaluation was complicated by the following: Propagation resistivities read low in reservoir rock, erroneously suggesting a water zone; nuclear porosity (TNPH) was doubtful due to the effects of enlarged hole on the measurements; and there were no cuttings returns to confirm possible dolomite presence. To understand and discriminate formation response from the environmental effects, an integrated workflow was developed to provide information on rock texture and producibility. Even though low in absolute value, propagation resistivities with multiple depths of investigation separate, suggesting conductive invasion. True formation resistivity can be resolved by 1D inversion of the resistivity array. The derived Rt is close to the laterolog-bit resistivity from the LWD imaging tool in both absolute values and profile, indicating a gas column section. To estimate porosity, three methods were compared, with the assumption that the formation was fully invaded: (1) Resistivity porosity obtained from inversion of Archie's law; (2) sigma porosity and (3) TNPH. TNPH was corrected for lithology effects by using LWD spectroscopy calcium and magnesium yields to quantify calcite and dolomite. For resistivity based porosity, variation in Archie m plays a key role. The results showed TNPH and sigma porosities were consistent with Archie porosity for m varying between 1.6 (fracture-rich interval) and 2.4 (predominance of vuggy pores). These textural variations are observed on the borehole images. The work demonstrated the value of integrating multiple LWD measurements to reduce uncertainties caused by borehole degradation and carbonate heterogeneity under challenging PMCD conditions.