Squeeze cementing is a routine well operation that has acquired a multitude of rules of thumb or procedural gimmicks because it evolved as a nontechnical field practice. The real technology controlling squeeze cementing behavior is readily available, but current practices are often contrary to technology published and engineering logic. Maximum pressures and displaced volumes are reported meticulously, even though their effect on results is unimportant. Formation breakdown often is accomplished at a high rate, causing larger fractures and use of more cement with no better results. Assumptions are made on the basis of whole cement entering the matrix and the concept of a horizontal pancake of cement, when both ideas are invalid.Both high-and low-pressure squeeze cementing techniques have their proper application. Fluid-loss control is important in set-through applications, but fluid loss must not be too low. Reduction of slurry density is often important. Pumpability time for any cement must be determined with proper regard for the mix water anticipated and the synergistic effect of some additives. The time must be sufficient to complete the job, but not so long that a firm set is jeopardized. Strength of set cement used in squeeze operations can be quite low and still retain all the pressure differential that most pipe can withstand.Successful evaluation is not conclusive with the conventional pressure test. A reverse differential is important to obtain a definitive test and provide for optimal reperforating conditions.

We became aware in early 1981 of a severe problem with casing failures opposite salts in the Little Knife field. A concerted engineering effort was initiated to isolate and to remedy the cause of failures. With the use of a relaxed invert-oil-emulsion drilling fluid and properly designed cementing programs, the problem has been arrested. In the 26 wells drilled in the Little Knife field since initiation of this drilling program, there have been no instances of casing failure.

Horizontal wells have shown such gains in productivity in many applications that the damage associated with longtime exposure to drilling fluid was, in many cases, accepted. In addition, the difficulty of removing formation damage in a horizontal well has compounded the problem. With many horizontal wells now being left in an openhole status, formation damage becomes even more important. Coiled tubing (CT) drilling has grown from four jobs in 1991 to over 120 (estimated) jobs in 1994. The primary motivations for this growth have been:The ability of CT drilling to finish drilling a well in soft formations faster than a rotary rig, andSafe, rigless underbalanced drilling to greatly reduce formation damage in horizontal wells. This paper reviews the causes of formation damage, both from fluid/solids invasion and stimulation techniques to remove damage. An analytical model is used to estimate the productivity index (PI) for various horizontal and vertical permeabilities, well lengths, and reservoir thicknesses for comparison with results from several case studies. Options for underbalanced drilling including fluid selection, gas lift, and seal technology are discussed. Candidate selection criteria for those evaluating the possibility of underbalanced horizontal drilling are presented. INTRODUCTION Horizontal wells are particularly vulnerable to formation damage due to long drilling mud exposure time relative to vertical wells (easily 30 times) and reduced cleanup velocity (easily 1/5) with production spread over the long horizontal. In spite of this, horizontal wells are the most important success story in the oil business in the last 10 years. Average gains in productivity1,2,3,4 of two to seven times the vertical wells in reservoirs with matrix permeability have fueled the growth of horizontal drilling. In reservoirs with natural fracture, productivity indices of 20 to 30 times the vertical have been observed with ultimate recovery several times greater than for vertical wells.5 Ultimate recovery improvement with matrix permeability is not widely reported, although 1.5 to 2 times vertical ultimate recovery is expected in two Canadian reservoirs. Although the ultimate recovery may not be improved, the accelerated production often makes horizontal wells more economically attractive in spite of the higher cost of the average horizontal well which is 1.2 to 2 times the vertica.3

Overview - No abstract available.

Summary Coiled tubing (CT) drilling is a rapidly growing new technology that has been used for shallow new wells and reentry applications. Averaged over the last 4 years, the number of wells directionally drilled with CT has doubled each year from 3 wells in 1991 to over 50 in 1995 (Fig. 1). A new market has evolved as being a major application for CT drilling. This market is through-tubing drilling. The motivation driving through-tubing drilling is low cost rigless reentry when overbalanced and safe drilling with Christmas tree and tubing in place when underbalanced (for reduced formation damage). The lower cost of mobilization of a coiled tubing unit (CTU) to an offshore platform or Arctic wellsite vs. a rotary rig provides additional economic incentive. In addition, the ease of drilling 4-3/4-in. and smaller boreholes with CT is an advantage in a region which does not have an established practice of slimhole drilling. The remaining key enabling technology for viable through-tubing drilling is the ability to sidetrack in casing below the tubing tail. The three technologies (cement sidetracking, whip stock in cement, and through-tubing whip stock) that have been developed for sidetracking are described in this paper. A mathematical model of forces, penetration rates, and torques for window milling with the cement sidetracking technique is presented. Window milling has been a "seat of the pants" operation in the past. to the authors'knowledge. this is the first published work on the mechanics of window milling. The analysis has shed much light on the interaction between motor bending stiffness, motor bend angle. and allowable advance rates for "timedrilling." The results from several yard tests are presented, and indicate some of the problems associated with sidetracking. The photographs of the sectioned hole/window illustrate the ledges caused downhole from minor" bottomhole assembly (BHA) changes. The cement sidetrack technique has been successfully applied many times in the field, and the results of one of these field applications is presented. Introduction When faced with a production problem in the past, an operator had nodrilling options unless the tubing was pulled and a conventional reentry well was drilled through production casing. While this is done at a reasonable coston most land operations, the rig mobilization costs offshore (and under Arctic conditions) dictate that only the wells with the highest potential can justify this type of expensive reentry. In areas of high rig mobilization costs, arigless through-tubing reentry can save 50% or more over the cost of a conventional reentry. With the advent of CT drilling. the option of through-tubing drilling has become a reality. Now, when faced with a production problem. an operator has the following through-tubing sidetracking options:–cement sidetracking (CS)–whipstock in cement (WIC)–through-tubing whipstock (TTW). Each of these techniques is discussed individually. Cement Sidetracking (CS). This technique is the most straightforward.