N. Last, SPE, British Petroleum Exploration Colombia; R. Plumb, SPE, Schlumberger Cambridge Research; R. Harkness, University of Southampton; P. Charlez, SPE, Total Exploration Production; J. Alsen, Triton Energy Corp.; M. McLean, SPE, British Petroleum Abstract An integrated approach to evaluating the causes of severe wellbore instability in the Cusiana field is described. The field is located in a tectonically active region of Colombia. Deterioration of the hole during drilling operations has led to excessive nonproductive time and expensive wells. The scale of the problem is unprecedented in the world. In wells costing tens of millions of dollars, millions per well could be attributed to poor hole conditions. This paper describes how the problem was addressed and what actions were taken to improve operational performance, resulting in reduced drilling costs. The improved understanding has contributed to better well planning, and improved drilling performance, and has underlined the need to consider all aspects of the drilling process to achieve improved hole conditions in a difficult geological setting. Introduction Nature of the Problem. Major drilling problems have been encountered in the Cusiana field. The field is located in the Llanos basin (Fig. 1), a tectonically active foothills region of the Eastern Cordillera in Colombia. The biggest problems stem from hole enlargement (Fig. 2), resulting in large amounts of cavings, often measured in truck loads per hour, which cause hole cleaning problems, stuck pipe, poor cementing, and often the need to sidetrack. The added complication of severe hole rugosity (alternating in-gauge and over-gauge sections) through interbedded sand-shale sequences. as in (Fig. 3) makes tripping, running casing and logging problematic, and renders large amounts of reaming necessary. The range of problems facing the drillers was formidable. Limited success was achieved by using experience from other parts of the world. For example, the use of higher mud weights, the conventional approach to solving hole enlargement problems, was unworkable because of the significant mud losses that occurred as the mud weight was raised. There was even some evidence that higher mud weights were accelerating the onset of poor hole conditions. Initially there was reluctance to accept the need for a new approach. Geological setting. The main features of the setting are illustrated in Fig. 1. Although the geological history includes an initial period of extension (including contemporaneous extensional growth faulting), the current tectonic environment is characterized by active thrusting toward the southeast, the assumed direction of maximum horizontal stress, with the thrust front marked by the Cusiana fault. To reach the reservoir in the hanging wall of the Cusiana fault, most production wells must penetrate the hanging wall of the Yopal fault and cross the Yopal fault. Although not detailed in Fig. 1, numerous smaller faults in the structure complicate the lithological sequence (sections are repeated) and produce abrupt and frequent changes in bedding dips. As an example, Fig. 4 is a detailed section through well X. Fig. 5 summarizes the generic lithological sequence. While problems have been encountered in most of the formations, by far the most problematic drilling has occurred in the alternating sand-shale sequence called the Carbonera In particular, losses and tight hole have occurred in the sandier units (C1, C3, C5 and C7), and wellbore enlargement has occurred in the shalier units (C2, C4, C6 and C8). Approach to Solving the Problem. Concerns over the increasingly high drilling costs and the lack of progress toward improved hole conditions led to the establishment of a multidisciplinary, multicompany team with the responsibility to help reduce costs associated with wellbore instability. This objective was challenging given the complexity of the problem, an aggressive drilling schedule and the absence of hard facts needed to make convincing arguments for change. In the end a relatively simple solution emerged: namely, manage the instability rather than trying to cure it completely. P. 147
Using Pressure-While-Drilling (PWD - measurement of downhole annulus pressure and temperature), an extensive campaign was undertaken on recent North Sea ERD wells to compare measured ECDs and static mud densities with hydraulic model predictions. In addition, the effects of drill pipe rotation and reciprocation have been analysed. The hydraulic model used to calculate downhole pressures predicts fluid downhole density and rheology according to surface properties, pressure and temperature input. Results show that using a Herschel-Bulckley law, ECDs are accurately predicted both in laminar and turbulent regimes. The causes of serious mud losses on two wells have been identified and operational procedures were changed to successfully reduce drilling risks. Introduction Complex wells have made, the control of downhole pressure whilst drilling more and more important. For instance, in HPIHT wells, the margin between pore and fracturing pressures can be very small, sometimes less than 0.1 SG. In such cases, the precise knowledge of downhole equivalent static density and ECD (Equivalent Circulating Density) are therefore of a strategic importance. In current Drilling Engineering, static density is adjusted at the surface and ECDs are calculated using hydraulic models, This practice sometimes leads to uncertainties larger than the required precision. Surface density which is generally measured (using a classical mud balance) in the mud pits or at the mud return is very sensitive to pressure and temperature. Depending on the case downhole density can be smaller or larger than surface density. The main input of ECD models are the well geometry (hole, string including tool joints, BHA, bit), mud rheology (calibrated on classical FANN measurements - mainly Bingham, Ostwald or Herschel-Bulckley) and flow rate. These models generally assume that the drill pipe is centred and they rarely take into account pipe vertical movements (reciprocation) and rotation. There is therefore no doubt that measurement of downhole Pressure1,2 and downhole temperature while drilling should allow to adapt real time the surface mud properties to obtain the required downhole conditions. It can also help in the development and improvement of hydraulics models by providing calibration points. Apart from the validation of static and ECD models a real time acquisition of downhole pressure and temperature can also provide valuable information about operational problems such as:–hole cleaning and optimisation of tripping procedures,–detection of abnormal thick cakes (reduced hole),–detection and control of mud losses,–better optimisation of bit hydraulics,–better estimation of LOT and FIT,–better control of downhole mud properties (mud sagging). The Dunbar field The Dunbar field is located in the northern part of the North Sea (Vicking Graben - Fig. la). The three main targets (below 3500mTVD) are in the middle and bottom Jurassic (respectively Brent and Stafjord reservoirs) and in the Triassic (Lunde reservoir). Depending on the location they can be oil bearing, gas bearing or both. Typical well design, mud weight strategy, and leak of test values are presented in Fig. lb. After batch setting a conductor pipe (26") 80 meters below the sea bed, drilling is initiated in 23 1/2" with a 1.08SG water base mud. The 18 5/8" casing shoe (where a LOT in the range of l.30SG to l.35SG is classically obtained) is set in the boltom of these recent (mainly sandy) sediments.
Charlez Total Oil Marine and A. Onaisi Total S.A. tipydghf 1~, Socie(y of %roleum Enginrnm, Inc This WPOr was P-for"pmwtdetion * She~RM Eunxk 'W held in Trondheim, NOHY, S-!0 July !99S This paper was~W~Mon by q n SPE Prqram Cmmifke follting reviw of information cdntainad In an ati subm~by ffie author(s) Contenk of me papr, as presented, haw ncdhn rtiawed by the Sacii & Peboleum Engineers and are subject bã by the ati[s)~mateflal, as pmsenkd &s nol necessatiiy Meet anỹ iti.m of the SOCW of Pehuleum Enginwm. ik ficem, or mem~fs Papers presenkd at meetings am sub-~m-an --by Editorial Cunmtiees of the Socie@ d um Enginwrs _nic reproduction, dlstdbution, or storage of any part of this papr for commercial purposes *out b Wn tise~& b socii of Pelmleum Engin-rs is pmhibikd Permission to mpduce in print is titi b an abstrad of not more than 3UJ q illustrations may not be COPW me abstract must contain mnspicuous =-edgement of Mere and by Mm the p8per was presented Write Llbrarlan. SPE, P.O Box~Ricfiafdwn, W 7~3.3836, US A , fax 01.972-SS2.9435 AbstractStuck pipes have three different origins : hole geometzy (excessive dog legs in highly dwiated wells), pack off (weIIbore instability or bad hole cleaning leading to a plugging of the annulus) and differential sticking (drill string embed&d into the mud cake due to an excessive difference between mud weight and reservoir pressure). This paper presents three d~erent examples of stuck pipes directly related to rock mechanics problems. The first one restits from a typical pack off in a highly unstable under compacted shale formation drilled in under bticed conditions. The second stuck pipe is qufie untypical since it occurred while driIling a 9 5~" cemented shoe track. Finally, the third one occurred while drilling the reservoir section of a highIy deviated well (72°inclination) and during a directional survey. The analysis of the surface data clearly showed that d~erential sticking was the cause of the stuck pipe, In the three cases, the well had to be side tracked where each time the cost was in the range of 1~.
Thermally Induced Fracturing (TIF) is often observed on injection wells. In this paper a well documented TIF case is presented and analysed. A numerical model is first presented where waterflooding is computed in two steps. In the first step, radial flow is considered and stress changes are computed. Depending on rock characteristics and flow rate the thermal effect (stress decrease) dominates over the pressure effect (stress increase). In the second step, as soon as the fracturing criterion is reached, the model automatically switches to a coupled two-phase flow option where a PKN type fracture has been incorporated. The main features of the model are summarized. To validate the model a field case has been analyzed where bottom hole pressure and temperature have been recorded. From field data it is shown that in the initial stage the height of the fracture varies and is thus different from the pay zone thickness. Use of Perkins and Gonzalez solution together with Prats formula allows to assess height and length evolution of the fracture. From this information, a mean fracture height can be assessed for the test duration. It is then shown that the pressure profile versus time is well given back using the numerical model, thus confirming the previous estimation of fracture dimensions. Introduction Waterflooding is still today the most common oil recovery method. It is aimed at improving recovery together with increasing production rate. Apart from any recovery process, injection of a cold fluid into a warmer reservoir induces thermal stresses, the main effect of which is to relax the hoop stress component over a certain distance. Indeed, the typical hoop stress profile (Fig. 1) around an injection well shows two distinct parts. In the section of the reservoir which has already been cooled, the thermal hoop stress is negative. Consequently, the total hoop stress is relaxed compared to its original value. This relaxation is, however, modulated by the hydraulic component (variation of stress associated with variation of pore pressure), which, depending on the voidage (balance between injection at the considered well and production from adjacent wells), can be either positive or negative. By contrast, in the zone which has not yet been affected by cooling, and for obvious equilibrium reasons, the hoop stress is greater than the original minor geostatic stress ah. Between these two zones, a very thin transition with a very steep stress gradient prevails. If hoop stress (initially equal to) relaxes below the injection pressure Pinj, a hydraulic fracture will initiate and then propagate until the transition zone (which we will call "stress wall" for obvious reasons) in the vicinity of which it stops. The temperature via the thermal stress thus acts as a propagation regulator. In waterflooding, the resultant back stresses (hydraulic and thermal) can no more be neglected as in classical hydraulic fracturing. Modelling of Thermal Induced Fracturing (T.I.F.) was initiated during the mid eighties by Perkins and Gonzales. In their paper, they assume that thermal conductivity can be neglected with respect to convection (in practice, this is almost always the case). Consequently, temperature is a step function and the reservoir area can be divided into a cold zone (at fluid temperature Tf) and a hot, undisturbed zone at reservoir temperature TR. Furthermore, as they assume a constant injection flow rate Q, the volume of the cooled zone can easily be calculated at any time t writing the energy balance between injected and received heat. As the fracture propagates, the cold zone initially radial lengthens parallel to the fracture direction. This suggests approximating the cooled region by an ellipsis confocal to the fracture direction (the fracture tip merges with the foci of the ellipsis - Fig. 2). The half-axes a0 and b0 are given by the following formulae: P. 397
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