Fracture ballooning usually occurs in naturally fractured reservoirs and is often mistakenly regarded as an influx of formation fluid, which may lead to misdiagnosed results in costly operations. In order to treat this phenomenon and to distinguish it from conventional losses or kicks, several mechanisms and models have been developed. Among these mechanisms under which borehole ballooning in naturally fractured reservoirs take place, opening/closing of natural fractures plays a dominant role. In this study a mathematical model is developed for mud invasion through an arbitrarily inclined, deformable, rectangular fracture with a limited extension. A governing equation is derived based on equations of change and lubrication approximation theory (Reynolds’s Equation). The equation is then solved numerically using finite difference method. Considering an exponential pressure-aperture deformation law and a yield-power-law fluid rheology has made this model more general and much closer to the reality than the previous ones. Describing fluid rheology with yield-power-law model makes the governing equation a versatile model because it includes various types of drilling mud rheology, i.e., Newtonian fluids, Bingham-plastic fluids, power-law, and yield-power-law rheological models. Sensitivity analysis on some parameters related to the physical properties of the fracture shows how fracture extension, aspect ratio and length, and location of wellbore can influence fracture ballooning. The proposed model can also be useful for minimizing the amount of mud loss by understanding the effect of fracture mechanical parameters on the ballooning, and for predicting rate of mud loss at different formation pressures.
Asphaltic and sand production problems are common production challenges in the petroleum industry. Asphaltic problem results from the depositions of heavy material (asphaltene) in the vicinity of the well which may cause severe formation damage. Asphaltic materials are expected to deposit in all type of reservoirs. Sand production refers to the phenomenon of solid particles being produced together with the petroleum fluids. These two problems represent a major concern in oil and gas production systems either in the wellbore section or in the surface treatment facilities. Production data, well logging, laboratory testing, acoustic, intrusive sand monitoring devices, and analogy are different techniques used to predict sand production. This paper introduces a new technique to predict and quantify the skin factor resulting from asphaltene deposition and/or sand production using pressure transient analysis.
Pressure behavior and flow regimes in the vicinity of horizontal wellbore are extremely influenced by this skin factor. Analytical models for predicting this problem and determining how many zones of the horizontal well that are affected by sand production or asphaltic deposition have been introduced in this study. These models have been derived based on the assumption that wellbore can be divided into multi-subsequent segments of producing and non-producing intervals. Producing intervals represent free flowing zones while non producing intervals represent zones where perforations are closed because of sand or asphaltic deposits.
The effective length of the segments of a horizontal well where sand and/or asphaltene are significantly closing the perforations can be calculated either from the early radial or linear flow. Similarly, the effective length of the undamaged segments can be determined from these two flow regimes. The numbers of the damaged and undamaged zones can be calculated either from the intermediate radial (secondary radial) or linear flow if they are observed. If both flow regimes are not observed, the zones can be calculated using type curve matching technique. The paper will include the main type-curves, step-by-step procedure for interpreting the pressure test without using type curve matching technique when all necessary flow regimes are observed. A step-by-step procedure for analyzing pressure tests using the type-curve matching technique will also be presented. The procedure will be illustrated by several numerical examples.
Carbonate formations are very complex in their pore structure and exhibit a wide variety of pore classes. Pore classes such as interparticle porosity, moldic porosity, vuggy porosity, intercrystalline porosity, and microporosity. Understanding the role of pore class on the performance of emulsified acid treatment and characterizing the physics of the flow inside is the objective of our study.
The study was performed using vuggy dolomite cores that represent mainly the vuggy porosity dominated structure, while the homogenous cores represent the intercrystalline pore structure. Core flood runs were conducted on 6 x 1.5 in. cores using emulsified acid formulated at 1 vol% emulsifier and 0.7 acid volume fraction. The objective of this set of experiments is to determine the acid pore volume to breakthrough for each carbonate pore class at different injection rates.
In this paper, a novel approach to interpret the core flood run results using thin section observations, tracer experiments, SEM, and resistivity measurements will be presented. Thin section observations provide means to study the vugs size and their distribution, connectivity, and explain the contribution of the pore class in the acid propagation. Relating the rotating disk experiments of emulsified acid with dolomite to our core flood run results will be also conducted in order.
The acid pore volumes to breakthrough for vuggy porosity dominated rocks were observed to be much lower than that for homogenous carbonates (intercrystalline pore structure). Also, the wormhole dissolution pattern was found to be significantly different in vuggy rocks than that in homogenous ones. Comparison of thin section observations, tracer results and the core flood runs results indicates that the vugs are distributed in a manner that creates a preferential flow path which can cause a rapid acid breakthrough and effective wormholing than those with a uniform pore structure. Rotating disk experiment results, demonstrating that the reaction of emulsified acid with dolomite is much lower than that with calcite, showed that the reaction kinetics played a role in determining the wormhole pattern.
The reliability of the estimated parameters in well test analysis depends on the accuracy of measured data. Early time data are usually controlled by the wellbore storage effect. However, this effect may last for the pseudo-radial flow or the boundary dominated flow. Eliminating this effect is an option for restoring the real data. Using the data with this effect is another option that can be used successfully for reservoir characterization.
This paper introduces a new technique for interpreting the pressure behavior of horizontal wells and fractured formations with wellbore storage. A new analytical model describes the early time data has been derived for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. Several models for the relationships of the peak points with the pressure, pressure derivative and time have been proposed in this study for different wellbore storage coefficients. A complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. The study has shown that early radial flow for short to moderate horizontal wells is the most affected flow regime by the wellbore storage. For long horizontal wells, the early linear flow is the most affected flow regime by the wellbore storage effect.
The most important finding in this study is the ability to run a short test and use the early time data only for characterizing the formation. This means there is no need to run a long time test to reach the pseudo-steady state. Therefore, from the wellbore storage dominated flow, the early radial and pseudo-radial flow can be established for horizontal wells and hydraulic fractured formations. A step-by-step procedure for analyzing pressure tests using the analytical models (TDS) and the type curves is also included in this paper for several numerical examples.
Saudi Arabian non associate gas reservoirs produce various amounts of condensate depending upon field and reservoir. In most cases, these wells are hydraulically fractured and at the initial stage after such stimulation treatment, each well needs to unload high quantity of the pumped fluid to ensure full potential. If the liquid starts accumulating in the wellbore during production, the well productivity will gradually decrease and eventually may stop producing. If the gas flow velocity in the production string is high enough, the gas will continue flowing and will carry the liquid droplets up the wellbore to the surface. The minimum velocity and critical gas rate (Qcrit) are therefore the determining factors while producing a well or several wells from a condensate-rich field so as to ensure the stable field production rate and maintain production plateau.
An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit, for given flowing wellhead pressure (FWHP), tubing diameter, and many other reservoir and completion properties. If the FWHP is set and a certain production rate is expected of a well, the program automatically computes the pressure drop due to friction, dynamic hydrostatic head, and the bottomhole pressure. Simultaneously, both Vcrit and Qcrit to unload the fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically selected and computation is continued until Qcrit is lower than the expected rate of the well. If this is not possible, the program will display appropriate message.
Several wells from a condensate gas reservoir are analyzed from a field that has to maintain certain production potential for a given number of years. The analyses show that the wells that are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit. For wells that were intermittently producing and ultimately could not sustain production were producing at rates below the critical values. Using this iterative model, those rates are automatically adjusted or new completion string is suggested to bring them back into production.
Stanitzek, Theo (AkzoNobel) | De Wolf, Corine (AkzoNobel) | Gerdes, Steffan (Fangmann Energy Services) | Lummer, Nils R. (Fangmann Energy Services) | Nasr-El-Din, Hisham A. (Texas A&M University) | Alex, Alan K. (AkzoNobel)
Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars.
Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples.
The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
Malik, Saeed Aslam (Oil & Gas Development Company Limited) | Channa, Munsif Hussain (Oil & Gas Development Company Limited) | Majeed, Arshad (Oil & Gas Development Company Limited) | Latif, Muhammad Khalid (Oil & Gas Development Company Limited) | Asrar, Muhammad (Weatherford)
During this period of energy crisis in Pakistan every effort is being made to produce every molecule of subsurface hydrocarbons. Particularly, the gas reservoirs which were not brought on production, due to low well deliverability or lack of required technology in the past are being explored and exploited. These include Tight, Low BTU, Sour and Acidic gas reservoirs. Such reservoirs pose specific problems related to drilling, production and development aspects.
This paper depicts drilling and testing of a reservoir which is above sea level and its initial reservoir pressure is approximately 1000 psi below the normal hydrostatic pressure. It is one of the lowest pressure reservoirs of the world which has been drilled with successful flow of gas. Underbalance drilling technology was chosen to drill this challenging reservoir. Primary objective of under balance Drilling (UBD) was to establish reservoir potential by acquiring virgin reservoir characteristics.
Historically, three wells have been drilled to test this reservoir. First two wells were drilled using conventional drilling methodology, both the wells experienced heavy mud loses during drilling and it was difficult to evaluate the production potential of this low pressure reservoir. Afterwards, pay zone of SML in third well X #02 was drilled and tested using Underbalance Drilling technique.
This paper further describes the problems faced by the operator to drill first two wells in terms of mud losses and evaluation of production potential of low pressure reservoir of SML. In conclusion, it was a successful application which happened due to exceptional team work from all project parties. This application has opened new horizons of exploration and production of such reservoirs particularly in Baluchistan and generally in Pakistan.
INTRODUCTION AND BACKGROUND
The E.L of interest is located in Baluchistan province of Pakistan. First well Y # 01 was drilled by another operator back in 1953-54 to depth of 1947 M. This well experienced severe mud losses against carbonates of Habib Rahi (HRL) and Sui Main Limestone (SML), and other down hole problems. Drill Stem tests in SML flowed to maximum of 3 MMSCFD of gas at BHP of 279 Psi. This gas rate was observed after re-perforations, pumping acids and swabbing for many days.
Ilyas, Asad (MOL Pakistan Oil & Gas Co. B.V.) | Arshad, Safwan (MOL Pakistan Oil & Gas Co. B.V.) | Ahmad, Jawad (MOL Pakistan Oil & Gas Co. B.V.) | Khalid, Arsalan (Schlumberger) | Mughal, Muhammad Haroon (Schlumberger)
This paper describes the challenges in determining average reservoir pressures in multi-layer completed wells during the span of their production period. The wells with single production tubing and get comingled flow from different reservoir layers exhibit complex down holeflow profiles. Therefore, it becomes difficult to acquire average pressures of each producing layer separately. Production log data can be utilized in these kinds of wells to calculate average individual layer pressures with the help of Selective Inflow Performance (SIP) technique for better production allocation and also to monitor pressure depletion effects with time.
The SIP provides a mean of establishing the IPR for each rate-producing layer. The well is flowed at several different stabilized surface rates and for each rate, a production log is run across the entire producing interval(s) to record simultaneous profiles of downhole flow rates and flowing pressure. Measured in-situ rates can be converted to surface conditions using PVT data. Although SIP theory only applies to single phase flow, the interpreter can restrict the IPR's computations to a particular phase; only contribution of the selected phase will be taken into account. To each reservoir zone corresponds for each survey/interpretation a couple [rate, pressure], used in the SIP calculation. The different types of IPR equations can be used for SIP interpretation: Straight line, Fetkovitch or C&n, and LIT relations. In the case of a gas wells, the pseudo pressure m(p) can be used instead of the pressure "p?? to estimate the gas potential. Although SIP is a useful technique to estimate average reservoir pressure in multi-layered system, but it has some limitations under certain circumstances.
The Selective Inflow Performance (SIP) technique has been implemented on some of the producing wells in north o f Pakistan. These wells have been completed in multiple producing reservoirs. Initially all these reservoirs were tested separately (with DST) to estimate their reservoir pressures and other parameters. However, due to adapted completion strategy, the producing layers were comingled with the option to monitor each layer's pressure depletion with the help of SIP technique in future. As per reservoir surveillance activity, Production logs are run on routine basis by utilizing SIP method and the same has been utilized for reservoir management and for simulation model updates.
The subject Gas Field is located in the Sulaiman Fold Belt (SFB) in Pakistan. A realistic 3D static model was constructed for the challenging multiple reservoirs in the Field which included both clastics and carbonates. Four main reservoir horizons were modeled.
The steps involved in the Reservoir engineering analyses were: analyze PVT, well test, Static Pressure Data, and Core. The static pressure analysis helped define hydraulic compartmentalization in the field.
WHFP measurements were not available in the desired accuracy and density. A surface network model was used with plant inlet pressure as the primary constraint in order to obtain the required information. Satellite based elevation information was used to establish an accurate model with respect to pressure drop due to liquid hold up in pipelines.
The History Match in the field was performed on a Zone by Zone basis. In the absence of a 3D seismic cube, many of the faults in the field could not be interpreted, yet their presence was predicted by a closely matching Sand Box Model. This was an important clue which led to a useful approach regarding the location of simulation faults distributed in the entire field. An innovative approach was used in order to calibrate the size of sand lenses in one of the zones.
The final step was the forecasting and development of Optimal Scenario using Economic analysis. Many scenarios were tested, and the optimal scenario was identified. Maximum use was made of existing wellbores through re-completion, and new drilling was minimized. Furthermore, the impact of increasing the currently low Gas Price was tested. It was concluded that doubling of the gas price of the field would increase the NPV 3 times delay abandonment by 6 years.
The Gas Field is located in the Sulaiman Fold Belt (SFB). Eighteen (18) wells in all, those have been drilled in the Field. Currently 12 wells are producing Gas. The primary target horizons in Field are the Sui Main Limestone (SML) and Lower Ranikot (LRKT). However, the Dunghun Limestone and Pab Sandstone are also producing in some of the wells. The depositional sequence consists of clastic and carbonate succession. The stratigraphy of the reservoirs is strongly influenced by the structural evolution of the Sulaiman Fold Belt and initial rifting of the Indian Plate.
Jadoon, M. Saeed Khan (Oil and Gas Development Company Limited) | Majeed, Arshad (Oil and Gas Development Company Limited) | Bhatti, Abid Husain (Oil and Gas Development Company Limited) | Akram, Mian M. (Oil and Gas Development Company Limited) | Saqi, Muhammad Ishaq (Pakistan Petroleum Limited)
Balanced drilling through naturally fractured reservoir and controlling loss for preventing reservoir damage and rehabilitation of normal production is a serious challenge in the Kohat-Potwar basin of Pakistan. The potential of hydrocarbons in these reservoir rocks has been masked by the overbalance drilling practices in this region. Due to overbalance drilling in fractured reservoirs and the use of heavy mud with barite blocks the fractures and that results in little or no flow during DST. The negative results of DSTs usually force the decision makers either to abandon the well or to re-test and establish the connectivity between the formation and the well bore.
The well under study was drilled in fractured carbonate reservoir rock to a depth of more than 5000 meters in Kohat-Potwar basin to target Datta and Lockhart formations. During drilling, due to complexities, well could not reach the Datta formation. No wire line and image logs could be obtained in Lockhart formation due to slim hole. The last 5-7/8 inch hole of this well had to be drilled by using Oil Based Mud (OBM) to control well bore instability, the same mud was used in the reservoir sections. During drilling, losses were observed in the reservoir section. On the basis of drilling information, the well was directly completed in the Lockhart formation. After completion, well was allowed to flow but no hydrocarbon surfaced. As Lockhart formation is proven producer, and it became a challenge to evaluate the reservoir for its production potential and to find out the causes of no flow from the formation.
After negative results of well test, all the data of G & G and mud logging was reviewed and detailed analysis of fractures network over the field were carried out to understand the well behavior. The data revealed that mud losses during drilling are i ndicative of fracture's presence in the tested zone(s) and fractures may have been plugged resulting in no flow during test. It was realized that reservoir has potential but connectivity between formation and the well bore need to be enhanced. Even after no flow during initial testing of the well for long period, bold decision of cleaning of the well was under taken and series of Nitrogen kick off jobs were undertaken to facilitate the well to flow. The nitrogen kick off were continued for four months, longest cleaning job ever undertaken in Pakistan and close monitoring of well was put inplace. After four months, WHFP started improving and flow of the hydrocarbons was observed and finally 730 bbl/d of oil and 1.6MMscfdgas were recorded. After the flow of the well, stimulation, with special recipe after lab experiments for OBM, was carried out with very encouraging results. After producing about one year, the well is still cleaning under natural flow.
In this paper, we would try to share our experiences about the use of OBM in fractured carbonate reservoirs, fracture characterization, reservoir damage and its remedial jobs. In addition to this, well performance, well cleaning and stimulation methodology, evaluation of non-flow behavior of well during initial testing and the lessons learned to transform failure to success will be explained.