This paper shows the results from chemical sand consolidation treatments used in the M1 sandstone as the main sand control method. For a successful implementation of this technique a workflow that combines field data, temperature modeling, laboratory analysis, petrophysics and geomechanics has been developed. Production results reports zero to near zero sand production with almost no impact on well productivity. Pre job design steps used to secure a consolidated reservoir after the treatment are described. Temperature is a key parameter to model since the resin is temperature activated. Laboratory tests and simulated temperature defines the curing time. A step rate test is used to calculate the injectivity index and evaluate the need for an acid stimulation treatment before the consolidation system is pumped into the well. This test is repeated after curing time to evaluate any possible impact on productivity. Determination of the Unconfined Compressive Strength (UCS) of the consolidation sand and critical sand production rate are also included in the analysis to understand sand production potential in the field. Chemical sand consolidation consists of two main components, resin and hardener. The consolidation fluid along with a pre-flush and an over-flush have typically been pumped into the well using production tubing. This sand control method has been proven to be relatively low in cost compared to other sand control techniques and the treatment can be performed in a relatively short period of time. These two characteristics and the positive production results observed thus far makes this technique attractive for upcoming sand control completions with unconsolidated reservoirs with similar characteristics to the M1 sandstone. In addition, conventional sand control methods rely on a particle size distribution (PSD) from a representative core sample for a successful implementation whereas chemical sand consolidation system is PDS independent.

Effective placement of stimulation fluids on horizontal, long interval and/or gravel-packed wells is critical for cost-efficient production enhancement. Successful case history work in 19991, using precision rotary jetting technology (R-Jet) on the end of coiled tubing (CT), demonstrated to the oil and gas industry that fluid placement is a key factor in removing near-wellbore damage and optimizing well stimulation treatments. This paper will review continued efforts relating to precision rotary jet technology including extensive laboratory tests using a full-scale gravel pack (GP) model. Tests were videotaped for further visual study. Established guidelines applying lab results, computer modeling, and field validation provide a well-engineered, non-damaging (low nozzle pressure) treatment for optimum stimulation performance. Proper damage identification coupled with skillful stimulation fluid design are important steps to a successful job and will be highlighted in the global R-Jet case histories. The data clearly shows that a highly effective method of placing stimulation fluids into a completion, such as sand control screens or slotted liners, is to use CT-conveyed, rotary speed-controlled, forward-angled radial jets. This technique yields 360° coverage of the treatment area, is more efficient than traditional bullheading and CT methods and allows reduced treatment volumes to be considered. It applies to a wide selection of completions including horizontal wells which can now be successfully stimulated at reasonable costs. Introduction Around the world there are tens of thousands of completions with screens and liners2 which could benefit from a reliable and cost-effective method for removing near-wellbore damage caused by drilling fluids, poor completion practices, fines migration and produced fluids. Very often a well begins producing with some form of damage (skin) caused by drilling (drill-in fluid filter cake) or completion damage (lost circulation material, perforating, dirty fluids). This skin will gradually increase over time as the screen/liner continue to collect migrating particulates (fines). Even if a sand control completion begins with no skin, there is an increased chance, due to the down-hole filter mechanism of a screen or liner, that fines, scale, organic deposits and/or drill-in fluid (DIF) filter cake will begin to plug the completion or GP proppant. There are inherent difficulties associated with trying to remove damage from the screen or liner, from the matrix of a GP or from perforation tunnels. Damage related to migrating fines is typically composed of either quartz particles (silica), silicates and alumino-silicates (clays and feldspars) or, more commonly, a combination of these. Scale, although most commonly deposited in up-hole tubulars, can also be found in the near-wellbore or screen area in the form of calcium carbonate, calcium sulphate or iron bearing scales (to name a few). Since downhole screens or liners often filter some of the described particles, these particulates tend to be much more concentrated in the near-wellbore or screen/liner area than in the formation. Damage associated with DIF (mostly on horizontal wells) is generally related to water-based, oil-based or synthetic oil-based mud comprised of polymers and particulates. These systems are extremely efficient in forming a thin DIF filter cake barrier to control mud losses to the formation and aid in drilling the well. Although efforts are made to minimize remaining DIF damage during the completion process, they often fall short, leaving damage that can be difficult to remove with conventional fluids or pumping techniques. The chemical formulations used to react with the various damage mechanisms have been previously reported in numerous papers1,3–7 and will be further investigated in this paper. Much of a well's damage acts as a downhole choke. Identifying the damage and properly designing the stimulation system to remove it is a painstaking process. However, even the best of fluids, improperly placed, are destined to fail. Major laboratory research on treatment fluid delivery methods and the use of controlled hydraulic energy to remove damage will be a central focus in this paper.

The feasibility of horizontal well technology is analyzed for the M1 reservoir of the Tarapoa Block. Applying advanced location deployment technologies of horizontal well, and optimizing key parameters are aimed to expand the application scale of horizontal wells in the Tarapoa Block. The approach is based on the research of genetic model of lithologic reservoirs, reservoir distribution characteristics and remaining oil distribution. The successful application of using combined drilling and completion technologies is already confirmed, and methods are described which focus on key parameters for optimizing horizontal well drilling and completion technology. From 2006 to 2014, nearly 67 wells have been successfully put on production on Tarapoa Block. According to petrogenesis, remaining oil of micro-structural type and well pattern imperfect type in M1 sandstone are major potential areas of applying horizontal technology. Because most wells are in a high water cut phase with thin net pays and bottom water drive, the optimal horizontal segment position, horizontal section length and well flow regime, need to be studied in order to ensure its economic benefit. Studies suggest that the relative height of the horizontal section to avoid bottom water should be more than 70%. Due to the small size of the remaining microstructures for the M1 reservoir, the longer the horizontal section, the greater the difficulty for controlling the trajectory. Considering that the produced water needs to be treated, the initial fluid volume of the horizontal wells should be controlled. Horizontal well technology in the Tarapoa Block has been successfully applied. Horizontal wells have accounted for 44% of the production of all new wells during the period and production from horizontal wells is 2.75 times that of the directional wells. They play a key role in stabilizing oil production, slowing declines and maintaining water control.