TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe primary objective of hydraulic fracturing is to create a propped fracture with sufficient conductivity and length to maximize or at least optimize well performance. In permeable reservoirs where transient flow is short lived, a fracture with a Dimensionless Fracture Capacity, F CD , of 2 is required to meet the design objective. In low permeability formations where transient flow can be extensive and where fracture fluid cleanup requires additional conductivity, an F CD in excess of 10 is desired. As a result, reservoir permeability becomes/is a key fracture design and analysis parameter. In higher permeability applications, permeability is determined simply, inexpensively, and routinely through conventional well testing techniques. Conventional well testing in tight formation gas reservoirs has not been proven as effective, can be expensive (cost of lengthy tests and production deferment), and is quite simply not routinely utilized. These reservoirs are often non productive without fracture stimulation and post fracture stimulation testing requires extensive shut-in time as the time to pseudo radial flow is proportional to the square of the fracture half-length. As a result, the development and routine use of any technique to determine permeability in these tight formation gas reservoirs has great value.In addition, without adequate well testing techniques and capabilities in tight gas reservoirs, the engineer is left with the use of log derived values of permeability which can often overstate in-situ permeability by factors of five to ten. Determination of in-situ permeability not only aids the well completion and stimulation but can be used to calibrate the log and core derived estimates of permeability improving performance predictions and field development. Prior papers have developed the use of After Closure Analysis techniques in permeable reservoirs, this paper will show the application of this technique to several tight gas formations in North America.This paper will demonstrate the following: 1) The effective application of this technique in tight gas formations in the U.S. and Canada, 2) Develop a cost effective and operationally simple means of collecting and analyzing the data, 3) Compare and contrast the technique to other methods of determining permeability in tight formation gas reservoirs, such as impulse, Perforation Inflow Diagnostic (PID), Closed Chamber Drill-Stem Tests (CCDST), post-frac build-up, production decline analysis, Modular Dynamic Formation Tester (MDT). 4) Show the application and value of calibrating log and core-derived permeability with in-situ measurements for improved well performance predictions.

Numerous technical publications were written in recent years on the effectiveness of reservoir simulation modeling in developing a tight gas resource. These papers question the applicability of existing numerical simulation methodologies to hydraulically fractured unconventional gas reservoirs. The rapidly changing dynamic flow behavior that occurs as fluids move from poor quality reservoir to a highly conductive fracture and then feed into an infinitely conductive wellbore creates complex solutions which are difficult to fully resolve with conventional reservoir simulation techniques. The lack of well to well dynamic interference during early stages of the production stacks the additional uncertainties around connected gas volume to the wellbore, thereby, increasing the chances of sub-optimal investment decision on well spacing, infill wells and number of fracs during the early stages of the field development. This paper proposes a reservoir simulation strategy and the workflow for unconventional gas reservoirs. The strategy outlines the need to systematically move from simple to complex modeling solutions while creating a learning loop. It proposes an early modeling focus on single wells in small sector models to understand the impact of stimulation and well design related uncertainties. The paper also identifies a learning stage that allows a progression to the next stage of simulation i.e. sector models. The workflow identified in the paper also presents the disadvantages of how an untimely progression from sector to full field modelling can negatively impact final investment decisions and the field development strategy. BP has successfully applied this framework in North America and this strategy has been outlined for reservoir simulation related work in the Sultanate of Oman to develop unconventional gas resources in Block 61.

BP's Khazzan-Makarem (KM) appraisal project is located in Central Oman. BP committed to appraise four deep tight gas reservoirs and has drilled seven wells to date. An Extended Well Test (EWT) facility is designed to provide a long term (multi-month) flow test of those wells.Basic information relating to trap, seal, areal extent, and Gas-in-Place (GIP) is not the most significant problem in this appraisal project; the most important issue is long term well performance. The tight gas nature of these reservoirs results in considerable uncertainty in prediction of future deliverability. It is not uncommon for tight gas wells to achieve excellent flow rates after fracture stimulation, yet decline precipitously over a short period of time (typically months) once on production. Prediction of well performance based on this early flow rate is a highly unreliable indicator of long term performance. This can result in drastic miscalculations for Full Field Development (FFD) planning and economics.Extensive surveillance activities are critical to evaluate this uncertain behavior. An examination of stimulation, well testing and Pressure-Build-Up (PBU) analysis in these wells provides the starting point for understanding well deliverability.BP's KM appraisal wells were planned to selectively target reservoirs addressing variations in reservoir quality and continuity. Completions were designed from the start, to facilitate extensive stimulation programs. Surveillance programs were constructed with permanent down hole gauges (PDHG) to provide critical real time information about the stimulation efforts, well testing, fluid composition analysis, and extreme long term (~ 1 year) PBU. All of this effort provides guidance in planning the EWT facility for an extended flow testing campaign which will feed into FFD planning. Achieving commercial rates in tight gas reservoirs in Oman has proved to be challenging. However this comprehensive appraisal and surveillance program is providing a growing level of confidence in the development potential of the Khazzan-Makarem project. Surveillance IssueValue Solution Implemented Areal extent of hydrocarbons -establish minimum commercial volume area Resource magnitude, development area for FFD, possible future well spacing, processing plant location Drill in a pattern that maximizes value issues; in this case, focus on pay quality rather than GIP.

BP's down hole instrumentation of the Khazzan tight gas appraisal wells provides a rare opportunity to quantify reservoir pressure and temperature dynamics. Several appraisal wells were initially tested for 3-4 weeks and subsequently shut-in for about a year. The continuous downhole gauge recordings of the resulting pressure build ups were then analyzed to quantify understanding of stimulation effectiveness, reservoir quality away from the wellbore, total producible connected gas, geomechanics and wellbore hydraulics. History matching of this gauge data provided confidence in predicting production profiles for full field development. This paper examines the pressure transient analysis (PTA) of one representative well in the field. The high quality build-up indicated that good quality rock extends to beyond the radius of investigation of the pressure transient and PTA did not reveal any barriers in an area of ~20 sq. km around the wellbore. The absence of boundaries and the possible extension of better quality reservoir have given BP the confidence to place an additional (and successful) appraisal well in the southwest of the block, thus extending the area that potentially will be a focus for early full field development. Installing permanent down hole gauges carried a high initial cost, but the value gained in quantifying subsurface uncertainty has proven the success of this technology application. It has also proved invaluable in executing hydraulic fracture stimulation. This high quality information boosts confidence in reservoir performance and long term deliverability leading to better informed business decisions regarding potential full field development. Value of Tight Gas Well TestingThe majority of tight gas wells require hydraulic fracturing to make them flow commercially. This process involves physical disturbance to the near-wellbore region that can extends a few hundred feet inside the reservoir. The shape of the propped fractures is still a subject of big debate in the tight-gas industry. Although many post-frac tests show linear-flow regime, this does not warranty the linearity of the fracture shape inside the matrix. Well tests are based on average theory and only give flow-related (effective) average numbers without giving any indication of shape or direction. Other datasets are required to support the conclusions of well-test results. This can be geological data to support interpreted geological features, near wellbore damage data to support skin damage, interference tests to support permeability interpretations, or more exotic data like microseismic to support propped fractures length and vertical extension. Interpreted well-test data are very critical in driving large projects. Fracture length is very important in driving well initial deliverability. Many tight-gas projects rely heavily upon this high-rate fracture dominated deliverability to support their development. Therefore, it is vital that great care is taken in addressing the uncertainties associated with the interpreted data, especiall...

Summary From the time that Union Texas Pakistan Inc., began operations in Badin, UTP personnel have observed several anomalies which are inconsistent with experience gained from drilling and production operations in other areas, i. e. the experience gained while working in relaxed sedimentary basins. There are several recognizable differences between Badin and relaxed sedimentary basins, and these vary from subtle to gross. These include:High fracture gradients.Bore hole breakout and its ability to often predict the location of porosity/permeability.Bore hole elongation.Shape of drill cuttings. The apparent reason for these differences is the high horizontal stresses. These high horizontal stresses effect many drilling and production operations. This paper will discuss the techniques used to identify these various stresses and some of the affects they may have on drilling and production operations. Introduction Union Texas Pakistan Inc., began drilling in the Badin concession, Sindh, Pakistan in January, 1979. The first discovery was Khaskeli #1 which, with additional wells became the Khaskeli Field. Khaskeli is now the operational center for UTP's Badin Operations which now include 40 fields of which 28 are producing. The subsurface in this area is composed predominantly of a thick sequence of clastics from the surface through the Middle Jurassic Chiltan Formation. The sedimentary column in this portion of the Lower Indus Basin is typical of basins seen in many other parts of the world. However, a preponderance of available data suggests that this is where the similarities end. The movement toward a free market economy in Pakistan has created an atmosphere where personnel with experience from other parts of the world's oil and gas producing areas can acquire first-hand knowledge of the varied subsurface strata in Pakistan. This system, allows for the free exchange of data and ideas and can lead, in addition to many other benefits, to more efficient drilling and production operations. Most of the experienced Petroleum Industry personnel gained their experience drilling and producing in tectonically relaxed sedimentary basins. That is, basins whose sedimentary stresses are controlled predominantly by the vertical stress. P. 385