Optimizing the number of casing strings has a direct impact on cost of drilling a well. The objective of the case study presented in this paper is the demonstration of reducing cost through integration of data. This paper shows the impact of high-resolution 3D geomechanical modeling on well cost optimization for the GS327 Oil field. The field is located in the Sothern Gulf of Suez basin and has been developed by 20 wells The conventional casing design in the field included three sections. In this mature field, especially with the challenge of reducing production cost, it is imperative to look for opportunites to optimize cost in drilling new wells to sustain ptoduction. 3D geomechanics is crucial for such cases in order to optimize the cost per barrel at the same time help to drill new wells safely. An old wellbore stability study did not support the decision-maker to merge any hole sections. However, there was not geomechanics-related problems recorded during the drilling the drilling of different mud weights. In this study, a 3D geomechanical model was developed and the new mud weight calculations positively affected the casing design for two new wells. The cost optimization will be useful for any future wells to be drilled in this area. This study documents how a 3D geomechanical model helped in the successful delivery of objectives (guided by an understanding of pore pressure and rock properties) through revision of mud weight window calculations that helped in optimizing the casing design and eliminate the need for an intermediate casing. This study reveals that the new calculated pore pressure in the GS327 field is predominantly hydrostatic with a minor decline in the reservoir pressure. In addition, rock strength of the shale is moderately high and nearly homogeneous, which helped in achieving a new casing design for the last two drilled wells in the field.

A reliable interpretation of Fracture Initiation Pressure (FIP) provides key information for both efficient well planning and construction. With the trend towards drilling ever deeper offshore wells, depleted zones and more complex well paths, the available mud weight window continues to tighten, so an improved knowledge of the FIP becomes essential in enabling robust designs and risk reduction strategies that together promote safe and efficient operations. A number of methods are currently used across the Industry to estimate FIP values for drilling and completion applications. These methods involve the direct interpretation of data from injection tests, such as Diagnostic Fracture Injection Tests (DFIT), Formation Pressure Integrity Tests (FPIT) or even Wireline Formation Tests (WFT). In this paper, the authors propose and present a simplistic yet effective approach to derive values for the FIP from such typical pumping test data. The method is based on long established principles linking the pressure, volume and in-situ rock properties of the system being tested. This paper provides a number of examples to demonstrate the application and validity of the approach, including the consideration of scaled laboratory block tests, through to actual field data. The relationship between FIP, FBP and closure pressure is presented and discussed for all of these cases. The method is based on early-time wellbore stiffness considerations and as such complements and augments the more conventional fracture closure analysis approach from decline data. Using this technique, additional valuable information may be extracted even from only partially completed tests, where formation breakdown analysis by conventional means may either be impossible to perform or at best is somewhat inconclusive. In summary, while there are many and varied techniques that have been widely developed in support of obtaining FIP, the quality, the repeatability and assurance of these approaches is often incomplete and can sometimes be misleading. The simplistic methodology that is outlined and presented here provides a complementary approach, with the potential to offer a more consistent estimation of this key pressure control parameter. The method also provides the possibility of identifying the FIP in those situations where the currently available data (quantity and/or quality) would suggest that conventional methods might well fail to deliver an unbiased interpretation.

Hydraulic fracturing is a commonly used completion approach for extracting hydrocarbon resources from formations, particularly in those formations of very low permeability. As part of this process the use of Diagnostic Fracture Injection Tests (DFIT) can provide valuable information. When the measured pressures in such tests are outside the expected range for a given formation, a number of possibilities and questions will arise. Such considerations may include: What caused such inflated pressures? What is the in-situ stress state? Was there a mechanical or operational problem? Was the test procedure or the test equipment at fault? What else can explain the abnormal behaviour? While there may not be simple answers to all of these questions, such an experience can lead to a technically inaccurate conclusion based on inadequate analysis.A recently completed project faced just such a challenge, initially resulting in poor hydraulic fracturing efficiency and a requirement to understand the root causes. In support of this, a thorough analysis involving a multi-disciplinary review team from several technical areas, including petrophysics, rock/ geo-mechanics, fluids testing/engineering, completions engineering, hydraulic fracture design and petroleum engineering, was undertaken. This paper describes the evolution of this study, the work performed, the results and conclusions from the analysis.The key factors involved in planning a successful DFIT are highlighted with a general template and a work process for future testing provided. The importance of appreciating the impact of the drilling and completion fluids composition, their properties and their compatibility with the formation fluids are addressed. The overall process and technical approach from this case study in tight gas fields, will have applicability across similar fields and the lessons learned could help unlock those reserves that are initially deemed technically or even commercially unattractive due to abnormal or unexpected behaviour measured during a DFIT operation.

The objective of this paper is to share Dragon Oil's experience to overcome challenges in drilling deep depleted reservoirs in the Cheleken Contract Area, Caspian Sea, Turkmenistan. Dragon Oil operates two producing oilfields; Lam and Zhdanov. The main targets described in this paper are from the Zhadanov field with the deepest target reaching around 4000m. This paper describes the challenges and experience from drilling complex wells in this area. The wells described in this paper penetrate various depleted reservoirs due to past production. The deepest reservoir consists of a sequence of interbedded sands with varying pore pressure due to geology and depletion due to production. The intra-reservoir shale layers are unstable and require high Mud Weights, often reaching technical limits (up to 20 ppg). The requirement of high mud weight to address shale instability is in contrast with the solutions for drilling depleted sand and the common drilling risks are mud losses and stuck pipe. An analysis of challenges, risk mitigations and lessons learned are discussed in this paper. Drilling a deep 6" directional hole is challenging and it requires continuous monitoring of the drilling fluid density. The pre-drill well planning is a key solution for preparing to deal with operational challenges and develop a strategy for reducing risk. This paper describes the important steps followed in the well planning process, risk mitigation options analyzed and incorporating the key elements in drilling program to overcome challenges. Some of the lessons learned from the experience of delivering wells in such complex area are: Implement 3D/4D PPFG and wellbore stability models to communicate depletion magnitudes accurately and effectively incorporate the risk in well planning to enable drilling with minimum overbalance.Map the correlation between depleted sand bodies (e.g. facies model) and assess impact of fault typesImplement Synthetic Oil Based Mud to improve wellbore condition and enhance drilling performance.Choose well trajectories to help transfer weight/torque to bottomMinimize the BHA static time across severely depleted zones This paper shares the experience from Turkmenistan and lessons learned from Dragon Oil's operations in Caspian Sea. This paper consolidates the well planning process, methods adopted to incorporate risk mitigation into drilling program and our recent experience from drilling complex wells targeting deep depleted reservoirs.

The Zhdanov Field is located on the eastern margin of the Caspian Sea and is geologically a part of the Apsheron-PreBalkan Fault Zone which crosses the Caspian Sea from Azerbaijan to Turkmenistan. Structurally, the field is part of an east-west orientated plunging anticline (hereafter referred to as the Cheleken Nose) that plunges westwards from the Cheleken Dome for over 25 km into the Caspian Sea. The structure of the Zhdanov Field formed in response to Pleistocene to Recent (post Apsheron) transpressive reactivation of a pre-existing fault at the Miocene and deeper levels (hereafter referred to as the Zhdanov Fault). Transpressive reactivation of the deep-seated fault created a southward verging reverse offset at the Miocene level with up to 600m of vertical displacement, with an unknown amount of lateral or strike slip offset. Data from the orientations of associated fault structures and borehole breakout data indicate that the stress field associated with the reactivation was a north-south compression with the maximum horizontal stress orientated 007 degrees N which is consistent with regional Caspian Sea tectonics. The overlying Pliocene to Recent, Red Series stratigraphy accommodated the reactivation and vertical displacement on the Zhdanov Fault on a series of extensional faults which strike NNE-SSW, orthogonal to the strike of the underlying fault. Because the extensional faults are dominantly post sedimentary, the faults have a planar geometry which form a set of domino style faults that show rigid rotation of the Red Series stratigraphy between faults. The extension direction of the planar faults is sub-parallel to the major east-west fold axis and orthogonal to the southward maximum dip direction of the fold structure which is to the south. The extension direction is therefore orthogonal to the extension direction that would be expected to occur due to gravity driven extension. Instead, the extensional faults represent lateral extension, or expulsion along the strike of the fold that was driven by the ongoing north-south compression which effectively prevented gravity driven extensional movement to the south. The extensional fault set all downthrow to the west aligning with the down plunge direction of the Cheleken Nose. The extensional fault set is likely to have been formed as a response to vertical offset in a structurally confined compressional / transpressional setting. The orientation and movement direction of the resulting extensional fault set is in direct contrast to that which would be expected in either gravity driven extension, or a positive Flower Structure that is commonly associated with transpressive strike slip faults. Lateral expulsion on extensional faults associated with transpression is valid from a kinematic and stress orientation stand point and is therefore a valid alternative to Flower Structures. At the Zhdanov Field, the series of tilted fault blocks created by the lateral extension may lead to new exploration opportunities with potential fault traps throughout the Red Series stratigraphy.